FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C., 20549
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to __________
State or
Exact Name of other IRS
Commission Registrant Jurisdiction Employer
File as specified of Identification
Number in its charter Incorporation Number
--------------- --------------- ------------- --------------
1-12609 PG&E Corporation California 94-3234914
1-2348 Pacific Gas and California 94-0742640
Electric Company
Pacific Gas and Electric Company PG&E Corporation
77 Beale Street One Market, Spear Tower
P.O. Box 770000 Suite 2400
San Francisco, California 94177 San Francisco, California 94105
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(Address of principal executive offices) (Zip Code)
Pacific Gas and Electric Company PG&E Corporation
(415) 973-7000 (415) 267-7000
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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.
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of latest practicable date.
Common Stock Outstanding, July 31, 2001:
PG&E Corporation 387,130,925 shares
Pacific Gas and Electric Company Wholly-owned by PG&E Corporation
PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY
Form 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2001
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION PAGE
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS 3
CONDENSED CONSOLIDATED BALANCE SHEETS 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS 6
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS 7
CONDENSED CONSOLIDATED BALANCE SHEETS 8
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS 11
NOTE 1: GENERAL 13
NOTE 2: THE CALIFORNIA ENERGY CRISIS 16
NOTE 3: VOLUNTARY PETITION FOR RELIEF UNDER CHAPTER 11 28
NOTE 4: PRICE RISK MANAGEMENT 31
NOTE 5: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING SOLELY
UTILITY SUBORDINATED DEBENTURES 33
NOTE 6: COMMIMENTS & CONTINGENCIES 34
NOTE 7: SEGMENT INFORMATION 40
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS 43
LIQUIDITY AND FINANCIAL RESOURCES 45
STATEMENT OF CASH FLOWS 50
RESULTS OF OPERATIONS 53
REGULATORY MATTERS 61
ENVIRONMENTAL MATTERS 64
PRICE RISK MANAGEMENT ACTIVITIES 67
LEGAL MATTERS 71
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 72
PART II. OTHER INFORMATION 73
ITEM 1. LEGAL PROCEEDINGS 73
ITEM 3. DEFAULTS UPON SENIOR SECURITIES 75
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 77
ITEM 5. OTHER INFORMATION 81
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 81
SIGNATURE 83
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PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share amounts)
Three months ended Six months ended
June 30, June 30,
----------------- ----------------
2001 2000 2001 2000
------- ------- ------ ------
Operating Revenues
Utility $ 2,309 $ 2,296 $ 4,871 $ 4,514
Energy commodities and services 2,704 3,342 6,817 6,132
------ ------ ------ ------
Total operating revenues 5,013 5,638 11,688 10,646
Operating Expenses
Cost of energy for utility 67 1,157 3,300 1,953
Cost of energy commodities and services 2,335 3,047 6,174 5,519
Operating and maintenance 897 743 1,585 1,460
Depreciation, amortization, and decommissioning 259 69 514 416
Reorganization professional fees and expenses 8 - 8 -
------ ------ ------ ------
Total operating expenses 3,566 5,016 11,581 9,348
------ ------ ------ ------
Operating income 1,447 622 107 1,298
Reorganization interest income 32 - 32 -
Interest income 42 26 77 50
Interest expense (312) (182) (559) (365)
Other income (expense), net 4 (14) (5) (23)
Income Before Income Taxes 1,213 452 (348) 960
Income tax provision (benefit) 463 204 (147) 432
------ ------ ------ ------
Net Income (Loss) $ 750 $ 248 $ (201) $ 528
====== ====== ====== ======
Weighted average common shares outstanding 363 361 363 361
------ ------ ------ ------
Earnings (Loss) Per Common Share, Basic
Net Earnings (Loss) $2.07 $ .69 $(0.55) $ 1.46
====== ====== ====== ======
Earnings (Loss) Per Common Share, Diluted
Net Earnings (Loss) $2.07 $ .68 $(0.55) $ 1.45
====== ====== ====== ======
Dividends Declared Per Common Share $ - $ .30 $ - $ .60
====== ====== ====== ======
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The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
--------------------------
June 30, December 31,
2001 2000
----------- ------------
ASSETS
Current Assets
Cash and cash equivalents $ 683 $ 899
Short-term investments 3,757 1,634
Accounts receivable:
Customers (net of allowance for doubtful accounts of
$103 million and $71 million, respectively) 2,894 4,342
Regulatory balancing accounts 46 222
Price risk management 2,656 2,039
Inventories 501 392
Income taxes receivable - 1,241
Prepaid expenses and other 447 406
------- -------
Total current assets 10,984 11,175
Property, Plant, and Equipment
Utility 24,341 23,872
Non-utility:
Electric generation 2,671 2,008
Gas transmission 1,559 1,542
Construction work in progress 617 900
Other 123 147
------- -------
Total property, plant, and equipment (at original cost) 29,311 28,469
Accumulated depreciation and decommissioning (12,350) (11,878)
------- -------
Net property, plant, and equipment 16,961 16,591
Other Noncurrent Assets
Regulatory assets 1,872 1,773
Nuclear decommissioning funds 1,332 1,328
Price risk management 1,045 2,026
Other 3,202 2,398
------- -------
Total noncurrent assets 7,451 7,525
------- -------
TOTAL ASSETS $ 35,396 $ 35,291
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The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
--------------------------
June 30, December 31,
2001 2000
----------- ------------
LIABILITIES AND EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Short-term borrowings $ 445 $ 4,530
Long-term debt, classified as current 10 2,391
Current portion of rate reduction bonds 290 290
Accounts payable:
Trade creditors 1,198 5,856
Regulatory balancing accounts 352 196
Other 535 459
Price risk management 2,548 1,999
Other 813 1,563
------- -------
Total current liabilities 6,191 17,284
Noncurrent Liabilities
Long-term debt 6,398 4,736
Rate reduction bonds 1,600 1,740
Deferred income taxes 1,795 1,656
Deferred tax credits 173 192
Price risk management 1,029 1,867
Other 3,903 3,864
------- -------
Total noncurrent liabilities 14,898 14,055
Liabilities Subject to Compromise
Financing debt 5,792 -
Trade creditors 5,168 -
------- -------
Total liabilities subject to compromise 10,960 -
Preferred Stock of Subsidiaries 480 480
Utility Obligated Mandatorily Redeemable Preferred Securities
of Trust Holding Solely Utility Subordinated Debentures - 300
Common Stockholders' Equity
Common stock, no par value, authorized 800,000,000 share,
issued 387,177,497 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 (2,305) (2,105)
Accumulated other comprehensive loss (109) (4)
------- -------
Total common stockholders' equity 2,867 3,172
Commitments and Contingencies (Notes 1, 2, 3, and 6) - -
------- -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 35,396 $ 35,291
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The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Six months ended June 30,
-------------------------
2001 2000
----------- ----------
Cash Flows From Operating Activities
Net income (loss) $ (201) $ 528
Adjustments to reconcile net income (loss) to
Net cash provided (used) by operating activities:
Depreciation, amortization, and decommissioning 514 416
Deferred income taxes and tax credits-net 120 111
Price risk management assets and liabilities, net (30) (20)
Other deferred charges and noncurrent liabilities (174) (369)
Net effect of changes in operating assets and liabilities:
Short-term investments (2,123) 139
Accounts receivable-trade 1,448 (505)
Inventories (109) 158
Accounts payable 586 594
Accrued taxes 1,241 127
Regulatory balancing accounts payable 332 190
Other working capital (791) 314
Other-net (116) (8)
------- -------
Net cash provided by operating activities 697 1,675
------- -------
Cash Flows From Investing Activities
Capital expenditures (818) (670)
Other-net (247) (10)
------- -------
Net cash used by investing activities (1,065) (680)
------- -------
Cash Flows From Financing Activities
Net repayments under credit facilities (1,033) (482)
Long-term debt issued 2,138 54
Long-term debt matured, redeemed, or repurchased (844) (346)
Common stock issued - 22
Dividends paid (109) (217)
------- -------
Net cash provided (used) by financing activities 152 (969)
------- -------
Net Change in Cash and Cash Equivalents (216) 26
Cash and Cash Equivalents at January 1 899 281
------- -------
Cash and Cash Equivalents at June 30 $ 683 $ 307
======= =======
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 268 $ 344
Income taxes paid (refunded) - net (1,241) 23
Transfer of liabilities and other payables subject to
compromise from operating payables and liabilities 10,960 -
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The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
Three months Six months
ended June 30, ended June 30
---------------- -----------------
2001 2000 2001 2000
------ ------ ------ ------
Operating Revenues
Electric $ 1,497 $ 1,801 $ 2,756 $ 3,402
Gas 812 495 2,115 1,112
------ ------ ------ ------
Total operating revenues 2,309 2,296 4,871 4,514
Operating Expenses
Cost of electric energy (362) 975 1,955 1,488
Cost of gas 429 182 1,345 465
Operating and maintenance 676 543 1,208 1,094
Depreciation, amortization, and decommissioning 222 44 439 345
Reorganization professional fees and expenses 8 - 8 -
------ ------ ------ ------
Total operating expenses 973 1,744 4,955 3,392
------ ------ ------ ------
Operating Income (Loss) 1,336 552 (84) 1,122
Reorganization interest income 32 - 32 -
Interest income 17 12 24 18
Interest expense (contractual interest of $195 million
and $396 million for the three- and six-months ended
June 30, 2001, respectively) (257) (144) (458) (285)
Other income (expense), net (2) - (6) (1)
------ ------ ------ ------
Income (Loss) Before Income Taxes 1,126 420 (492) 854
Income tax provision (benefit) 424 198 (200) 398
------ ------ ------ ------
Net Income (Loss) 702 222 (292) 456
Preferred dividend requirement 6 6 12 12
------ ------ ------ ------
Income (Loss) Available for (Allocated to) Common Stock $ 696 $ 216 $ (304) $ 444
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The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
-------------------------
June 30, December 31,
2001 2000
---------- -----------
ASSETS
Current Assets
Cash and cash equivalents $ 132 $ 111
Short-term investments 3,125 1,283
Accounts receivable:
Customer (net of allowance for doubtful accounts of
$54 million and $52 million, respectively) 1,547 1,711
Related parties 20 6
Regulatory balancing account 46 222
Inventories:
Gas stored underground and fuel oil 262 146
Materials and supplies 126 134
Income taxes receivable - 1,120
Prepaid expenses and other 210 45
------ ------
Total current assets 5,468 4,778
Property, Plant, and Equipment
Electric 16,787 16,335
Gas 7,554 7,537
Construction work in progress 266 249
------ ------
Total property, plant, and equipment (at original cost) 24,607 24,121
Accumulated depreciation and decommissioning (11,521) (11,120)
------ ------
Net property, plant, and equipment 13,086 13,001
Other Noncurrent Assets
Regulatory assets 1,843 1,716
Nuclear decommissioning funds 1,332 1,328
Other 1,487 1,165
------ ------
Total noncurrent assets 4,662 4,209
------ ------
TOTAL ASSETS $ 23,216 $ 21,988
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The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
---------------------------
June 30, December 31,
2001 2000
----------- ------------
LIABILITIES AND EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Short-term borrowings $ - $ 3,079
Long-term debt, classified as current - 2,374
Current portion of rate reduction bonds 290 290
Accounts payable:
Trade creditors 345 3,688
Related parties 7 138
Regulatory balancing accounts 352 196
Other 300 363
Deferred income taxes 45 172
Other 297 670
-------- --------
Total current liabilities 1,636 10,970
Noncurrent Liabilities
Long-term debt 3,370 3,342
Rate reduction bonds 1,600 1,740
Deferred income taxes 1,087 929
Deferred tax credits 173 192
Other 3,001 2,968
-------- --------
Total noncurrent liabilities 9,231 9,171
Liabilities Subject to Compromise
Financing debt 5,792 -
Trade creditors 5,356 -
-------- --------
Total liabilities subject to compromise 11,148 -
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
Stockholders' Equity
Preferred Stock Without Mandatory Redemption Provisions
Nonredeemable-5% to 6%, outstanding 5,784,825 shares 145 145
Redeemable-4.36% to 7.04%, outstanding 5,973,456 shares 149 149
Common stock, $5 par value, authorized 1,606 1,606
800,000,000 shares, issued 321,314,760 shares
Common stock held by subsidiary, at cost, 19,481,213 shares (475) (475)
Additional paid-in capital 1,964 1,964
Accumulated deficit (2,283) (1,979)
Accumulated other comprehensive loss (42) -
-------- --------
Total stockholders' equity 1,064 1,410
Commitments and Contingencies (Notes 1, 2, 3, and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 23,216 $ 21,988
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The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Six months ended
June 30,
------------------
2001 2000
------- -------
Cash Flows From Operating Activities
Net income (loss) $ (292) $ 456
Adjustments to reconcile net income to
Net cash provided (used) by operating activities:
Depreciation, amortization, and decommissioning 439 345
Deferred income taxes and tax credit-net 12 170
Price risk management assets and liabilities, net (38) -
Other deferred charges and noncurrent liabilities (272) (303)
Net effect of changes in operating assets and liabilities:
Short-term investments (1,842) (6)
Accounts receivable 619 (46)
Income tax receivable 1,120 -
Inventories (108) 15
Accounts payable 606 399
Accrued taxes - 99
Regulatory balancing accounts, net 332 190
Other working capital (99) (16)
Other-net 366 (5)
------- -------
Net cash provided by operating activities 843 1,298
------- -------
Cash Flows From Investing Activities
Capital expenditures (575) (572)
Other-net 34 (16)
------- -------
Net cash used by investing activities (541) (588)
------- -------
Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities (28) 31
Long-term debt matured, redeemed, or repurchased (252) (216)
Common stock repurchased - (275)
Dividends paid - (250)
Other-net (1) 4
------- -------
Net cash used by financing activities (281) (706)
------- -------
Net Change in Cash and Cash Equivalents 21 4
Cash and Cash Equivalents at January 1 111 80
------- -------
Cash and Cash Equivalents at June 30 $ 132 $ 84
======= =======
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 265 $ 261
Income taxes paid (refunded) - net (1,120) -
Transfer of liabilities and other payables subject to
compromise from operating payables and liabilities 11,148 -
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The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
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 company of Pacific Gas and Electric Company, a debtor-in-possession, (the Utility) on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. Effective with PG&E Corporation's formation, the Utility's interests in its unregulated subsidiaries were transferred to PG&E Corporation. As discussed further in Note 3, on April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code (Bankruptcy Code) in the United States Bankruptcy Court for the Northern District of California (Bankruptcy Court). Under Chapter 11, 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.
This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and the Utility. 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. 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.
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, and PG&E Corporation's and the Utility's other reports filed with the Securities and Exchange Commission since their 2000 Form 10-K 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
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, required PG&E Corporation and the Utility to recognize all derivatives, as defined in the Statement, on the balance sheet at fair value. PG&E Corporation's transition adjustment to implement this new Statement on January 1, 2001 resulted in a non-material decrease to earnings and a decrease of $243 million to accumulated other comprehensive income. The Utility's transition adjustment to implement this new Statement resulted in a non-material decrease to earnings and an increase of $90 million to accumulated other comprehensive income.
Derivatives are classified as price risk management assets or price risk management liabilities on the balance sheet. Derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. For derivatives that are effective hedges, depending on the nature of the hedge, changes in the fair value are either offset by changes in the fair value of the hedged assets or liabilities through earnings or recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Net gains or losses recognized for the three- and six-month periods ended June 30, 2001, were included in various places on the income statement including energy commodities service revenue, cost of energy commodities and services, other income (expense), net, or interest income or interest expense.
Contracts for the physical delivery of purchase and sale quantities under the normal course of business 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 Financial Accounting Standards Board(FASB) is considering an interpretation by the Derivatives Implementation Group (DIG) that indicates that certain forward contracts with embedded optionality cannot qualify for the normal purchases and sales exception. Any gains or losses from the changes in fair value of these contracts in PG&E Corporation's non-regulated businesses will impact the income statement unless those contracts qualify for hedge accounting treatment. PG&E Corporation is currently reviewing its contracts to evaluate the impact of these interpretations on its financial statements, and will implement this guidance, as applicable, on a prospective basis.
As of June 30, 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 March 2014.
The Utility had Power Exchange (PX) block-forward contracts valued at $243 million, which were derecognized in February 2001 when they were seized by California Governor Gray Davis for the benefit of the State, acting under California's Emergency Services Act (the Act). The block-forward contracts had an unrealized gain at the time they were seized. Under the Act, the State must pay the Utility for 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 the contracts. The Utility has filed a complaint against the State to recover the value of the seized contracts.
The Utility is party to various electric and gas bilateral contracts, some of which were terminated in the first six months of 2001. See Note 2. The value of certain gas contracts terminated during the first six months of the year was $60 million, net of taxes and regulatory impact. This balance is being amortized out of accumulated other comprehensive income at the same rate that hedged items are recognized in earnings.
Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income 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 Six months
ended June 30, ended June 30,
-------------------- ---------------------
2001 2000 2001 2000
(in millions) ------ ------ ------- ------
Net Income (Loss) $ 750 $ 248 $ (201) $ 528
----- ----- ------ -----
Weighted average common shares outstanding 363 361 363 361
Add: Outstanding options reduced by the number of shares
that could be repurchased with the proceeds from such
purchase - 1 - 1
----- ----- ----- -----
Shares outstanding for diluted calculation 363 362 363 362
----- ----- ----- -----
Earnings (Loss) per common share, basic $2.07 $ .69 $(0.55) $1.46
Earnings (Loss) per common share, dilutive $2.07 $ .68 $(0.55) $1.45
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Accumulated Other Comprehensive Income (Loss)
The objective of PG&E Corporation's and the Utility's accumulated other 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.
New Accounting Pronouncements
In June 2001, the FASB issued SFAS No. 141, "Business Combinations." This Standard, which applies to all business combinations accounted for under the purchase method completed after June 30, 2001, prohibits the use of pooling-of- interests method of accounting for business combinations and provides a new definition of intangible assets. PG&E Corporation and Pacific Gas and Electric Company do not expect that implementation of this Standard will have a significant impact on its financial statements.
Also, in June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." This Standard eliminates the amortization of goodwill, and requires that goodwill be reviewed annually for impairment. This Standard also requires that the useful lives of previously recognized intangible assets be reassessed and the remaining amortization periods be adjusted accordingly. This Standard is effective for fiscal years beginning after December 15, 2001, and affects all
goodwill and other intangible assets recognized on the company's statement of financial position at that date, regardless of when the assets were initially recognized. PG&E Corporation and Pacific Gas and Electric Company have not yet determined the effects of this Standard on its financial statements.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This Standard is effective for fiscal years beginning after June 15, 2002, and provides accounting requirements for asset retirement obligations associated with tangible long-lived assets. PG&E Corporation and Pacific Gas and Electric Company have not yet determined the effects of this Standard on its financial statements.
NOTE 2: THE CALIFORNIA ENERGY CRISIS
In 1998, California became one of the first states in the country to implement electric industry restructuring and establish a competitive market framework for electric generation. Electric industry restructuring was mandated by the California Legislature in Assembly Bill 1890 (AB 1890). The electric industry restructuring established a transition period, mandated a rate freeze, and included a plan for recovery of generation-related costs that were expected to be uneconomic under a competitive market (transition costs). The California Public Utilities Commission (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 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 purchase all electricity for 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 kilowatt-hour (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 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 March 2001, 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.
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 are incurred after March 27, 2001 and could not be used to pay amounts owed to creditors. Although the rate increase was authorized immediately, the Utility did not begin collecting in rates the 3.0 cent per Kwh surcharge until June 1, 2001, when the rate design was adopted by the CPUC. As a result of the delay in implementation, the additional surcharge that went into effect on June 1, 2001 was 3.5 cents per kWh, of which 0.5 cents per kWh amortizes the under-collection that accrued between March 27 and the June 1, 2001 implementation date over the twelve month period ending June 2002.
In light of the magnitude of the under-collected 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 $272 million at June 30, 2001, and believes that the funds will be adequate to maintain its operations through and beyond 2001. In addition, PG&E Corporation believes that 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.
Transition Period and Rate Freeze
California's deregulation legislation passed by the California Legislature in 1996 established a transition period, which was to begin in 1998. During this period, electric rates for all customers were frozen at 1996 levels, with rates for residential and small commercial customers being reduced in 1998 by 10% and frozen at that level. During the transition period, investor-owned utilities were given the opportunity to recover their transition costs. Transition costs were generation-related costs that 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 under-collected wholesale electricity costs as of the end of the earlier determined transition period will be less than the August 31, 2000 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.) On February 14, 2001, the Federal Energy Regulatory Commission (FERC) ordered that the ISO could only buy power on behalf of creditworthy entities. The FERC order also stated that the ISO could continue to schedule power for the Utility as long as it comes from its own generation units and is routed over its own transmission lines. Despite the FERC orders, the ISO continued to bill the Utility for the ISO's wholesale power purchases. On April 6, 2001, the FERC issued a further order directing the ISO to implement its prior order, which the FERC clarified, applying to all third-party transactions whether scheduled or not. In light of the FERC's April 6, 2001 order, the Utility has not recorded any such estimated ISO charges after April 6, 2001, except for the ISO's grid management charge, although the Utility has accrued the full amount of the ISO charges up to April 6, 2001 in the accompanying financial statements. On June 13, 2001, the FERC denied the ISO's request for rehearing of its April 6, 2001 order.
On June 26, 2001, the Bankruptcy Court issued a preliminary injunction prohibiting the ISO from charging the Utility for the 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 issuing the injunction, the Bankruptcy Court noted that the FERC orders permit the ISO to schedule transactions that involve either a creditworthy buyer or a creditworthy counterparty, and noted the existence of unresolved issues regarding how to ensure these creditworthiness requirements for real-time transactions and emergency dispatch
orders issued by the ISO to power sellers. The Utility believes that its only responsibility for third party power delivered to its customers is to pay the DWR the amount collected from customers, whether the third party power is purchased by a creditworthy buyer or whether the purchase is facilitated by a creditworthy counterparty.
The generation-related cost component of frozen retail rates, which provides for recovery of generation costs, including wholesale electricity purchased by the Utility and, if available, for recovery of transition costs, was 5.4 cents per kWh, during the six months ended June 30, 2000. In 2001, the CPUC approved two rate increases, which increased the generation-related cost component. On January 4, 2001, the generation-related cost component increased 1.0 cent per kWh. On June 1, 2001, the generation-related cost component increased by 3.5 cents per kWh. As discussed below, the CPUC approved an average 3.0 cents per kWh surcharge for power costs incurred after March 27, 2001, but the Utility did not begin collecting in rates the 3.0 cents per kWh surcharge until June 1, 2001. At the time of implementation, the actual surcharge was 3.5 cents per kWh to reflect the under-collection that accrued due to the delay in implementation.
Through April 6, 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 Consolidated Statement of Operations. The amount of under-collected purchased power costs incurred for the six-month period ended June 30, 2001 was approximately $.9 billion. The under-collected purchased power costs accrued as of March 31, 2001, included an estimated cost of $579 million for the month of March based upon usage and historical market price estimates. In May 2001, the ISO provided the invoice for its March purchases, which totaled $257 million. An adjustment for the difference between the estimated amount at March 31, 2001, and the actual amount was recorded in the second quarter as a reduction to the Cost of Electric Energy in the Consolidated Statement of Operations.
Under current CPUC decisions, if the under-collected purchased power costs are not recovered through frozen rates by the end of the transition period, they cannot be recovered. However, in the CPUC decision adopting the 3.0 cent per kWh rate increase, the CPUC indicated that in light of recent legislative action and regulatory developments, it would be premature and unwise to opine as to the ultimate disposition of this under-collection. 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.
The under-collected 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. Therefore, such costs are expensed as incurred.
Mitigation Efforts
The Utility is actively exploring ways to reduce its exposure to wholesale electricity price volatility and to recover its written-off under-collected wholesale electricity costs and Transition Cost Balancing Account (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.
On October 16, 2000, the Utility joined with Southern California Edison (SCE) and The Utility Reform Network (TURN) in filing a petition with the FERC requesting that the FERC; (1) immediately find the California wholesale electricity market to be not workably competitive and the resulting prices to be unjust and unreasonable; (2) immediately impose a cap on the price for energy and ancillary services; and (3) institute further expedited proceedings regarding the market failure, mitigation of market power, structural solutions, and responsibility for refunds.
On December 15, 2000, the FERC issued an order in response to the above filing. The remedies proposed by the FERC included, among other things; (1) eliminating the requirement that the California investor-owned utilities must sell all of their power into, and buy all of their power needs from, the PX; (2) modifying the single price auction so that bids above $150 per megawatt hour (MWh) (15.0 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.
During June and July 2001, a FERC administrative law judge conducted settlement
negotiations between power sellers, representatives of the State of California,
California investor-owned utilities and other interested parties, to try to
reach an agreement about calculation of potential refunds. The settlement
negotiations were unsuccessful and on July 25, 2001, the FERC issued an order
that limits potential refunds to the ISO and PX spot markets during the period
of October 2, 2000 through June 20, 2001, and adopted a refund calculation
methodology that uses daily spot gas prices and includes a 10% premium on prices
after January 5, 2001, to reflect the added risk to the sellers resulting from
the lack of creditworthiness of the California investor owned utilities. The
ISO has 15 days to submit a re-creation of the mitigated prices that result from
using the methodology to the administrative law judge (ALJ) overseeing the
proceedings. The FERC directed the ALJ to make findings of fact with respect
to: (1) the mitigated price in each hour of the refund period; (2) the amount
of refunds owed by each supplier according to the methodology established; and
(3) the amount currently owed to each supplier (with separate quantities due
from each entity) by the ISO, the investor owned utilities, and the State of
California. The ALJ is to then certify his findings of fact to the FERC within
45 days after the receipt of the material from the ISO. A prehearing conference
is scheduled to be held on August 13, 2001 to address procedural issues related
to the evidentiary hearings developing a record on the scope and methodology for
calculating refunds announced in the July 25, 2001 order.
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 stated 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 alleged 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 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. The Utility filed a request for rehearing of the CPUC's decisions. Under applicable rules, if the CPUC has not acted on the request within 60 days of filing, the request is deemed denied. While the CPUC has not yet acted on the Utility's request, the 60-day period has expired and the Utility believes the decisions have become final. Therefore, the Utility intends to refile its case in federal district court shortly.
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, requires 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 (QFs) contracts, existing bilateral contracts, and ancillary services (the California Procurement Adjustment or CPA). Currently, the CPA is just a calculation and is not paid to the DWR. Initially, the DWR 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. 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. The ISO billed the Utility for its costs to purchase power to cover the amount of the Utility's net open position not covered by the DWR. As discussed above, the Utility has expensed these costs from January through April 6, 2001 in the accompanying financial statements. Although the Utility continues to receive bills from ISO for its power purchases made after April 6, 2001, the Utility has recorded only the ISO's grid management charge as an expense after April 6, 2001. It is not clear whether and to what extent the Utility will ultimately be responsible for the ISO costs billed to the Utility.
In light of the FERC's April 6, 2001 order the Utility has not recorded any such estimated ISO charges after April 6, 2001, except for the ISO's grid management charge.
Further, it is unclear how much of the ISO's power purchases have been made by the DWR on behalf of the Utility's customers. On June 21, 2001, the Utility received a request from the DWR that the Utility pay the DWR the amounts required by current CPUC orders for the DWR's out-of-market purchases made on
behalf of the Utility's customers between January 17, 2001 and June 2, 2001, pursuant to AB 1X. The Utility has previously received invoices from the ISO for what the Utility believes may be the same energy.
The amounts requested by the DWR in its June 21, 2001 invoices are based on the amounts that the Utility is authorized to collect from customers pursuant to AB 1X and current CPUC orders, which are significantly less than the ISO invoices, which are based on market prices. However, the CPUC orders establishing the amount the Utility is required to collect and pay the DWR are interim and subject to revision when the CPUC allocates the DWR's overall revenue requirements under AB 1X. Since the Utility believes that it is merely a pass through entity for such costs and related revenues, the Utility does not reflect these amounts in its Consolidated Statements of Operations.
A determination that the DWR is the creditworthy buyer or counterparty for the ISO's third-party purchases in accordance with the FERC tariffs could result in a reversal of the prior recorded ISO expenses and could result in a material increase to earnings depending on the amount ultimately authorized by the CPUC to be collected by the Utility from ratepayers on the DWR's behalf.
On November 22, 2000, the Utility filed an application with the CPUC seeking approval of a five-year RSP beginning on January 1, 2001. The Utility requested an initial average rate increase of 22.4%. The Utility also proposed that it receive actual costs, including a regulated return, for electricity generation provided by it with the idea that profits that would have been generated at market rates be recovered from customers later in the five-year rate stabilization period. With respect to Diablo Canyon Nuclear Power Plant (Diablo Canyon) the Utility has proposed to defer all profits (discussed below in "Diablo Canyon Benefits Sharing"), until 2003, when the allocation of revenues between ratepayers and shareholders will be readjusted. The readjustment is intended to allow, by the end of 2005, the total net revenues earned by Diablo Canyon, over the five-year plan, to be allocated equally between shareholders and ratepayers according to existing CPUC decisions.
On January 4, 2001, the CPUC issued an emergency interim decision denying the Utility's request for a rate increase. Instead, the decision permitted the Utility to establish an interim surcharge applied to electric rates on an equal- cents-per-kWh basis of 1.0 cent per kWh, subject to refund and adjustment. The surcharge was to remain in effect for 90 days from the effective date of the decision. The Utility was required to establish a balancing account to track the revenue provided by the surcharge and to apply these revenues to ongoing wholesale electricity costs. The surcharge was made permanent in the CPUC's March 27, 2001 decision, referred to below.
On January 26, 2001, an assigned CPUC commissioner's ruling was issued in the Utility's RSP proceeding. The ruling stated that in phase one of the case, the scope of the proceeding would 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 under-collected balances in the utilities Transition Revenue Accounts (TRAs) to their respective TCBAs and reviewing the generation memorandum accounts, and (3) considering whether the rate freeze has ended only on a prospective basis.
On January 30, 2001, the independent consultants engaged by the CPUC issued their review report on the Utility's financial position as of December 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 was authorized immediately, the 3.0 cents per kWh surcharge would not be collected in rates until the CPUC established an appropriate rate design for the surcharge, which was adopted on May 15, and implemented on June 1, 2001. The actual surcharge that went into effect on June 1, 2001 was 3.5 cents per kWh, of which 0.5 cents per kWh amortizes the under-collection accrued between March 27, 2001, and the June 1, 2001 implementation date. 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 over-collections, or (3) to the extent any administrative body or court denies the refunds of over-collections in a proceeding where recovery has been hampered by a lack of cooperation from the Utility. The 3.0 cents per kWh surcharge is in addition to the emergency interim surcharge approved on January 4, 2001, which the CPUC made permanent in this decision. The CPUC also modified accounting rules in response to a proposal made by TURN as described below.
Also, on March 27, 2001, the CPUC issued a decision ordering the Utility and the other California investor-owned utilities to pay the DWR a per-kWh price equal to the applicable generation-related retail rate per kWh established for each utility, for each kWh that 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 1.0 cent per kWh interim surcharge adopted by the CPUC on January 4, 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 June 1, 2001. On June 1, 2001, the CPUC adopted an additional rate surcharge of 3.516 cents per kWh. 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. For power supplied through May 31, 2001, the amount of power scheduled 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 scheduled to the Utility 45 days earlier and the Utility's company-wide average generation-related rate of 6.471 cents per kWh, as ordered by the CPUC. For power scheduled to the Utility after June 1, 2001, the Utility began remitting to the DWR in the more precise manner as outlined in the CPUC decision discussed above.
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, 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, QF 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 3.0 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.
Initially, the DWR advised the CPUC that its revenue requirement for the DWR's
power purchases was $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 3.0 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 3.0 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).
On July 23, 2001, the DWR filed information concerning its revenue requirements with the CPUC. The DWR stated that it seeks to collect $13.072 billion from electric customers for the period January 17, 2001 through December 2002. Of this amount, the DWR seeks to collect approximatewly $5.2 billion from the Utility's customers. The Utility is required currently to pay the DWR approximately $0.10 per kWh for each kWh provided by the DWR, including all of the 3.0cent surcharge approved by the CPUC in March 2001. The DWR's filing indicated that the average cost it is seeking from California utility customers is 10.8 cents per kWh for 2001 and 13.7 cents per kWh in 2002. On July 24, 2001, the Utility requested that the DWR hold a public hearing on its revised revenue requirement because the DWR's filing lacked sufficient detail to determine the impact its revenue requirements may have on ratepayers and the Utility.
In March 2001, the CPUC also adopted TURN's proposal to transfer on a monthly basis the balance in each utility's TRA to the utilities' TCBA. The TRA is a regulatory balancing account that is credited with total revenue collected from ratepayers through frozen rates and which tracks under-collected 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 filed an application for rehearing of this decision. The Utility also requested the Bankruptcy Court to enjoin the CPUC from requiring the Utility to implement the regulatory accounting changes.
On June 1, 2001, the Bankruptcy Court issued a decision denying the Utility's request and granting the CPUC's motion to dismiss the complaint. The Utility has filed an appeal of the Bankruptcy Court's order. The Utility will continue to pursue all legal challenges to this unlawful CPUC decision.
Qualifying Facilities Contracts
In early 2001, the Utility had been paying only 15% of amounts due QFs. A number of QFs 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. 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 QFs. 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. Since May 2001, the QFs under contract to the Utility are being paid in full for power purchased since early April 2001.
In July 2001, the Utility signed five-year agreements with 131 of its QFs, ensuring the Utility and its customers receive a reliable supply of electricity at an average energy price of 5.37 cents per kilowatt-hour. Under the terms of the agreements, the Utility will assume the QF contracts and pay the pre- petition debt on these 131 QF contracts, totaling $740 million, on the effective date of the plan of reorganization. The total amount the company owed to QFs when it filed for Chapter 11 was approximately $1 billion. The agreements represent 75% of debt owed to QFs. For certain of these QFs, if the effective date has not occurred by July 15, 2003, the Utility will pay 2% of the principal amount of the pre-petition debt per month until the effective date of the plan of reorganization or until July 15, 2005, when it will pay the remaining pre- petition debt. By locking into the average fixed cost, the Utility will help protect its customers from the price fluctuations in the wholesale market. Each of the agreements requires formal approval from the U.S Bankruptcy Court. Most of the agreements have already been approved, and the Utility will be making filings for the remainder in the near future.
Bilateral Contracts
Under the terms of AB 1890, the Utility was required to purchase all of its power from the PX and ISO to meet the needs of its customers. On August 3, 2000, after the California energy crisis had begun, the CPUC approved the Utility's use of bilateral contracts, subject to the Utility reaching agreement with the CPUC on reasonableness standards. After two months of unsuccessful discussions with the CPUC, on October 16, 2000, the Utility 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. Some of these contracts were terminated by the counterparties who were entitled to do so in the event of a the decline in the Utility's credit quality to below investment grade, certain of these contracts were terminated by the counterparties. The terms of the contracts require that at termination, the contracts be settled at the then market-value of the contract. One contract has been settled with the counter- party for $405 million. Two others are in negotiations and have combined estimated market values at termination date that ranges from $126 million to $217 million. The settled contract and lower end of the range of market values for the contracts under negotiation total $552 million and have been recognized as a reduction to the Cost of Electric Energy in the Consolidated Statement of Operations. As of June 30, 2001, remaining individual contracts range in size from approximately 61,200 MWhs to 3,504,000 MWhs of supply annually. The contracts extend to 2003.
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 six months ended June 30, 2001, the PX credits reduced electric revenue by $80 million. The Utility ceased paying most of these credits in December 2000, and as of June 30, 2001, the total of accumulated credits for direct access customers that have not been paid by the Utility is approximately $513 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 the December 15, 2000 FERC order, the FERC ordered that ratemaking for the Utilty's remaining generation be returned to the jurisdiction of the CPUC. 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 June 30, 2001, the book value of the Utility's net investment in hydroelectric generation assets was approximately $585 million.
On June 15, 2001, the Utility filed testimony in its RSP proceeding to present its revenue requirement for cost-based rates for its retained generation, including its hydroelectric and nuclear facilities, qualifying facilities, bilateral contracts, and ancillary services. The Utility argued that the revenue requirements for its hydroelectric facilities should be based on a market valuation of its hydroelectric assets, as required by current law, at a minimum value of $4.1 billion. Based on this valuation, the Utility argued that its rate freeze ended as early as April 2000, notwithstanding the implementation of the retroactive changes to the transition period ratemaking mechanisms discussed above. Combined with the revenue requirements for other retained generation and purchase power costs, the Utility proposed a 2001 revenue requirement of $6.7 billion. The Utility was directed by the CPUC to present other revenue requirement scenarios. These alternate scenarios produce 2001 revenue requirements between $3.9 billion based on the amount of unrecovered capital costs at April 30, 2001 and assuming the rate freeze ended before January 1, 2001, to $9.9 billion which amount assumes the rate freeze has not ended. It is likely that the CPUC will not act on the Utility's 2001 revenue requirement filing until after the CPUC acts on the DWR's revenue requirement. In such event, it is uncertain whether current rates as they may be apportioned between the Utility and the DWR will be sufficient for the Utility to recover the revenue requirements that may eventually be adopted by the CPUC.
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 auditedprofits 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. In the Utility's June 15, 2001 revenue requirement testimony in its
rate stabilization proceedings, the Utilty proposed that the revenue requirements for Diablo Canyon should reflect the 50/50 sharing of net benefits between shareholders and ratepayers using a market revenue benchmark and actual ongoing costs. It is uncertain what future ratemaking will be applicable to Diablo Canyon.
Note 3: VOLUNTARY PETITION FOR RELIEF UNDER CHAPTER 11
On April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under Chapter 11, 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. Subsidiaries of the Utility, including PG&E Funding LLC (which holds Rate Reduction Bonds, discussed further in Note 2) and PG&E Holdings LLC (which holds stock of the Utility), are not included in the Utility's petition. The Utility's Consolidated Financial Statements have been prepared in accordance with the American Institute of Certified Public Accountants' Statement of Position 90-7 (SOP 90-7), "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code," and on a going concern basis, which contemplates continuity of operation, realization of assets and liquidation of liabilities in the ordinary course of business. However, as a result of the filing, such realization of assets, and liquidation of liabilities are subject to uncertainty.
Certain claims against the Utility in existence prior to the filing of the petition for relief are stayed while the Utility continues business operations as a debtor-in-possession. These claims are reflected in the June 30, 2001, balance sheet as "liabilities subject to compromise." Additional claims (liabilities subject to compromise) may arise subsequent to the filing date resulting from (1) negotiations; (2) rejection of executory contracts, including leases; (3) actions by the Bankruptcy Court; (4) further developments with respect to disputed claims; (5) proofs of claim; or (6) other events. Payment terms for these amounts will be established through the bankruptcy proceedings. Claims secured against the Utility's assets ("secured claims") also are stayed, although the holders of such claims have the right to move the court for relief from the stay. Secured claims are secured primarily by liens on substantially all of the Utility's assets and by pledged accounts receivable from gas customers. The Bankruptcy Court has approved making the regular interest payments on the Utility's secured debt.
A creditors' committee has been appointed as an official committee and, in accordance with the provisions of the Bankruptcy Code, will have the right to be heard on all matters that come before the Bankruptcy Court. The Utility expects that the creditors' committee will play an important role in the negotiation of the terms of any plan of reorganization.
Since the filing, the Bankruptcy Court has approved various requests by the Utility to permit the Utility to carry on its normal business operations, and pay certain pre-petition obligations. Additionally, the Utility has secured approval for approximately $1.5 billion in capital expenditures for on-going business needs such as upgrading and improving transmission lines and substations. The Utility's current actions are intended to allow the Utility to continue to operate while the bankruptcy proceedings continue.
On January 10, 2001, the Utility suspended the payment of its fourth quarter 2000 common stock dividend of $109 million, declared in October 2000, to PG&E Corporation and its wholly owned subsidiary PG&E Holdings, LLC Until its financial condition is restored, the Utility is precluded from paying common stock dividends to PG&E Corporation and PG&E Holdings, LLC In addition, the
Utility's Board of Directors did not declare the regular preferred stock dividends for the three-month period ended January 31, 2001, or for the three- month period ended April 30, 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.
In July 2001, the Bankruptcy Court granted a motion that the Utility had filed requesting that the court extend until December 6, 2001, the period during which the Utility has the exclusive right to file a plan of reorganization in its Chapter 11 case. Under the normal timeline, the exclusivity period would have ended on August 6, 2001, 120 days after the Utility's April 6, 2001, Chapter 11 filing. The Utility filed for an extension of the exclusivity period in the event that additional time is needed to continue discussions with creditors and to develop and file a comprehensive and feasible plan of reorganization. The Bankruptcy Court may confirm a plan of reorganization only upon making certain findings required by the Bankruptcy Code, and a plan may be confirmed over the dissent of non-accepting creditors and equity security holders if certain requirements of the Bankruptcy Code are met. The payment rights and other entitlements of pre-petition creditors and the Utility's shareholders may be substantially altered by any plan of reorganization confirmed by the Bankruptcy Court. Although it is the Utility's intent to pay all valid claims, pre- petition creditors may receive, under a plan, less than 100% of the face value of their claims, and the interests of the Utility's equity security holders may be affected. A plan of reorganization could materially change the amounts and classification reported in the consolidated financial statements.
The Utility is not able at this time to predict the outcome of its bankruptcy case, the terms and provisions of any plan of reorganization, or the effect of the Chapter 11 reorganization process on the claims of the creditors of the Utility or the interests of the Utility's equity security holders. However, the Utility believes, based on information presently available to it, that cash available from operations will provide sufficient liquidity to allow it to continue as a going concern for the foreseeable future.
NOTE 4: PRICE RISK MANAGEMENT
PG&E Corporation's net gain (loss) on trading contracts for the three- and six- month periods ended June 30, 2001 are $93 million and $121 million, respectively.
PG&E Corporation's and the Utility's ineffective portion of changes in fair
values of cash flow hedges are immaterial for the three- and six-month periods
ended June 30, 2001. PG&E Corporation's and the Utility's estimated net
derivative gains or losses included in accumulated other comprehensive income
(loss) at June 30, 2001 that are expected to be reclassified into earnings
within the next twelve months are net losses of $59 million and $38 million,
respectively. The actual amounts reclassified from accumulated other
comprehensive income (loss) to earnings can differ as a result of market price
changes. PG&E Corporation expects approximately $20 million of these net
derivative losses to be offset when the items being hedged are recognized in
earnings.
The schedule below summarizes the activities affecting accumulated other comprehensive loss from derivative instruments for the three- and six-month periods ended June 30, 2001.
Three months ended Six months ended
June 30, 2001 June 30, 2001
----------------------- -----------------------
PG&E PG&E
(in millions) Corporation Utility Corporation Utility
----------- ------- ----------- -------
Beginning derivative gains (losses) included in
accumulated other comprehensive income (loss)
$ (315) $ (52) $ (243) $ 90
Net gain (loss) of current period
hedging transactions 178 (8) 149 (7)
Net gain (loss) reclassified to
earnings 31 19 (12) (124)
----- ----- ----- -----
Ending derivative gains (losses)
included in accumulated other
comprehensive income (loss) (106) (41) (106) (41)
Foreign currency translation
adjustment (3) (1) (3) (1)
----- ----- ----- -----
Ending accumulated other comprehensive
income (loss) at June 30, 2001 $ (109) $ (42) $ (109) $ (42)
===== ===== ===== =====
|
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 $9 million and $34 million due to the nonperformance of counterparties during the three- and six-month periods ended June 30, 2001, respectively. Counterparties considered to be investment grade or higher comprise 84% of the total credit exposure. At June 30, 2001, PG&E Corporation's and the Utility's gross credit risk exposure amounted to $1.1 billion and $142 million, respectively.
NOTE 5: 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% Cumulative Quarterly Income Preferred Securities (QUIPS), with an aggregate liquidation value of $300 million. Concurrent with the issuance of the QUIPS, the Trust issued to the Utility
371,135 shares of common securities with an aggregate liquidation value of $9 million. The Trust in turn used the net proceeds from the QUIPS offering and issuance of the common stock securities to purchase subordinated debentures issued by the Utility with a face value of $309 million, due 2025. These subordinated debentures are the only assets of the Trust. Proceeds from the sale of the subordinated debentures were used to redeem and repurchase higher- cost preferred stock.
The Utility's guarantee of the QUIPS, considered together with the other obligations of the Utility with respect to the QUIPS, constitutes a full and unconditional guarantee by the Utility of the Trust's contractual obligations under the QUIPS issued by the Trust. The subordinated debentures may be redeemed at the Utility's option beginning in 2000 at par value plus accrued interest through the redemption date. The proceeds of any redemption will be used by the Trust to redeem QUIPS in accordance with their terms.
Upon liquidation or dissolution of the Utility, holders of these QUIPS would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to the date of payment.
On March 16, 2001, the Utility deferred quarterly interest payments on the Utility's 7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025, until further notice in accordance with the indenture. The corresponding quarterly payments on the 7.90% QUIPS, issued by the Trust 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 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 6: COMMITMENTS AND CONTINGENCIES
Nuclear Insurance
The Utility has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). Under this insurance, if a nuclear generating facility suffers a loss due to a prolonged accidental outage, the Utility may be subject to maximum retrospective assessments of $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.
Workers' Compensation Security
On May 9, 2001, the Department of Industrial Relations approved the Utility's security deposit of approximately $401 million in collateral provided by surety bonds, providing backing for the Utility's status as a self-insured for workers' compensation. This represents a decrease of approximately $55 million in security from the previous year, reflecting a reduction in estimates of workers' compensation obligations. These bonds are backed up by an indemnity at the PG&E Corporation level.
The Utility has for several years utilized surety bonds as its method of providing security (other forms of acceptable security include LOC's, cash, or securities.) In February 2001, several of the surety bonds provided cancellation notices, citing concerns about the Utility's financial situation. However, under the state-developed bond form, the canceling sureties are not released of their obligation for workers' compensation claims occurring before the effective date of the cancellation until released by the State.
The State has continued to apply the canceled bond amounts totaling $185 million towards the $401 million requirement. The Utility was able to supplement the difference through three additional active surety bonds totaling $216 million. This cancellation has not, to date, impacted the Utility's self-insured status under California law, or its ability to meet current plan obligations.
Environmental Remediation
Utility
The Utility may be required to pay for environmental remediation at sites where it has been or may be a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act, and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, and sites used by it for the storage or disposal of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances, even if it did not deposit those substances on the site.
The Utility records an environmental remediation liability when site assessments indicate remediation is probable and a range of reasonably likely clean-up costs can be estimated. The Utility reviews its remediation liability quarterly for each identified site. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The remediation costs also reflect (1) current technology, (2) enacted laws and regulations, (3) experience gained at similar sites, and (4) the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within the range of possible costs, the Utility records these costs at the lower end of this range.
As of June 30, 2001, the Utility expects to spend $306 million for hazardous waste remediation costs at identified sites, including divested fossil-fueled power plants. The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. A change in estimate may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. If other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater
than anticipated, the Utility could spend as much as $459 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 $306 million and $320 million at June 30, 2001 and December 31, 2000, respectively. The $306 million accrued at June 30, 2001 includes (1) $139 million related to the pre-closing remediation liability, associated with the divested generation facilities discussed further in the "Generation Valuation" section of Note 2, and (2) $167 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 $306 million environmental remediation liability, the Utility has recovered $139 million through rates, and expects to recover another $86 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.
On June 28, 2001 the Bankruptcy Court entered its "Order on Debtor's Motion for Authority to Continue Its Hazardous Substances Cleanup Program." The Utility is authorized to expend (1) up to $22 million in each calendar year in which this Chapter 11 case is pending to continue its hazardous substance remediation programs and procedures, and (2) any additional amounts necessary in emergency situations involving post-petition releases or threatened releases of hazardous substances, if such excess expenditures are necessary in the Utility's reasonable business judgment to prevent imminent harm to public health and safety or the environment (provided that the Utility seeks the Court's approval of such emergency expenditures at the earliest practicable time), in each case as described in the motion.
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") has been conducting a nationwide enforcement investigation regarding the historical compliance of coal-fueled electric generating stations with various permitting requirements of the Clean Air Act. Specifically, the EPA and the U.S. Department of Justice have recently 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, the EPA visited both facilities. PG&E NEG believes this request for information is part of the EPA's industry-wide investigation of coal-fired power plants' compliance with the Clean Air Act requirements governing plant modifications. PG&E NEG also believes that any changes it made to these plants were routine maintenance or repair and, therefore, did not require permits. The EPA has not issued a notice of violation or filed any enforcement action against PG&E NEG at this time. Nevertheless, if the EPA disagrees with PG&E NEG's conclusions with respect to the changes PG&E NEG 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.
From time to time various states in which our facilities are located consider the adoption of air emissions standards that may be more stringent than those imposed by EPA. On May 11, 2001, the Massachusetts Department of Environmental Protection (DEP) issued regulations imposing new restrictions on emissions of NOx and SO2, mercury and carbon dioxide from existing coal-fired power plants. These restrictions will impose more stringent annual and monthly limits on NOx and SO2 emissions than currently exist and will take effect in stages, beginning in October 2004 if no permits are needed for the changes necessary to comply, and beginning in 2006 if such permits are needed. DEP has informed PG&E NEG that, based upon its current understanding of the facilities' plans for compliance with the new regulations, it believes that permits will be needed and that the initial compliance date will therefore be 2006. However, the need for permits triggers an obligation to meet Best Available Control Technology, or BACT, requirements. Compliance with BACT at the facilities could require implementation of controls beyond those otherwise necessary to meet the emissions standards in the new regulations. Mercury emissions are capped as a first step and must be reduced by October 2006 pursuant to standards to be developed. Carbon dioxide emissions are regulated for the first time and must be reduced from recent historical levels. PG&E NEG believes that compliance with the carbon dioxide caps can be achieved through implementation of a number of strategies, including sequestrations and offsite reductions. Various testing and recordkeeping requirements are also imposed.
By 2002, PG&E NEG plans to have approximately 5,100 MW of generating capacity in operation in New England. The new Massachusetts regulations affect primarily its Brayton Point and Salem Harbor generating facilities, representing approximately 2,300 MW. Through 2006, it may be necessary to spend approximately $265 million to comply with these regulations. In addition, with respect to approximately 600 MW (or about 12%) of PG&E NEG's New England capacity, PG&E NEG may need to implement fuel conversion, limit operations, or install additional environmental controls. These new regulations require that PG&E NEG achieve specified emission levels earlier than the dates included in a previous Massachusetts initiative to which it had agreed.
The federal Clean Water Act generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency and/or EPA. All of the facilities that are required to have such permits either have them or have timely applied for extensions of expired permits and are operating in substantial compliance with the prior permit. At this time, three of the fossil-fuel plants owned and operated by PG&E NEG's affiliate USGen New England, Inc. (Manchester Street, Brayton Point and Salem Harbor stations) are operating pursuant to permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and we anticipate 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 USGen New England's cost to comply with new permit conditions could be approximately $60 million through 2005. It is possible that the new permits may contain more stringent limitations than the prior permits.
PG&E NEG anticipates spending up to approximately $330 million, net of insurance proceeds, through 2006 for environmental compliance at currently operating facilities, which primarily addresses: (a) new Massachusetts air regulations made public on April 23, 2001 affecting the Brayton Point and Salem Harbor Stations; (b) wastewater permitting requirements that may apply to the Brayton Point, Salem Harbor and Manchester Street Stations; and (c) requirements, to which we agreed, that are reflected in a consent decree concerning wastewater treatment facilities at the Salem Harbor and Brayton Point Stations.
During April 2000, an environmental group served an affiliate of PG&E NEG, USGen New England, Inc., and other of its subsidiaries with a notice of its intent to file a citizen's suit under RCRA. The group stated that it planned to allege that USGen New England, as the generator of fossil fuel combustion wastes at Salem Harbor and Brayton Point, has contributed and is contributing to the past and present handling, storage, treatment and disposal of wastes at those facilities which may present an imminent and substantial endangerment to the public health or the environment. During September 2000, USGen New England signed a series of agreements with the Massachusetts DEP and the environmental group that address and resolve these matters. The agreements, which have been filed in federal court and are now incorporated in a consent decree, require, among other things, that USGen New England alter its existing wastewater treatment facilities at both 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 cost of these activities is expected to be approximately $21 million, and they are underway.
LEGAL MATTERS
Utility
The Utility's Chapter 11 bankruptcy on April 6, 2001, discussed in Note 3 automatically stayed the litigation described below against the Utility.
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 recorded a legal reserve in its financial statements in the amount of $160 million for these matters. PG&E Corporation and the Utility believe that, after taking into account the reserves recorded as of December 31, 2000, the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation's or the Utility's financial condition or future results of operations.
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 the Utility's
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 AB 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.
A complaint, Gillam, et al v. PG&E Corporation and Pacific Gas and Electric ompany, et al, is pending in the U.S. District Court for the Northern District of California. The complaint alleges that PG&E Corporation and the Utility violated federal securities laws, generally accepted 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 operations.
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, June 30, 2001 $184
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NOTE 7: 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 generally accepted accounting principles, 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 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, the Utility, provides natural gas and electric service to its customers.
PG&E National Energy Group
PG&E Corporation's subsidiary, 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, 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 and its affiliates which includes PG&E Gas Transmission Northwest(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 and six months ended June 30, 2001, and 2000 was as follows:
PG&E National Energy Group
PG&E
Integrated Interstate Corporation
Energy and Pipeline NEG & other
(in millions) Utility Total NEG Marketing Operations Eliminations Eliminations (2) Total
------ -------- ----------- ---------- ----------- --------------- -----
Three months ended June 30, 2001
Operating revenues $ 2,305 $ 2,708 $ 2,640 $ 55 $ 13 $ - $ 5,013
Intersegment revenues (1) 4 48 39 9 - (52) -
------ ------ ------ ----- ----- ------ ------
Total operating revenues 2,309 2,756 2,679 64 13 (52) 5,013
Net Income (Loss) 696 71 53 19 (1) (17) 750
Three months ended June 30, 2000(4)
Operating revenues 2,293 3,345 3,086 267 (8) - 5,638
Intersegment revenues(1) 3 17 4 13 - (20) -
----- ----- ----- ----- ----- ------ ------
Total operating revenues 2,296 3,362 3,090 280 (8) (20) 5,638
Net income 216 32 18 13 1 - 248
Six months ended June 30, 2001
Operating revenues 4,865 6,823 6,708 111 4 - 11,688
Intersegment revenues (1) 6 141 123 18 - (147) -
------ ------ ------- ------ ----- ------ -------
Total operating revenues 4,871 6,964 6,831 129 4 (147) 11,688
Net Income (Loss) (304) 125 88 38 (1) (22) (201)
Total assets at June 30, 2001(3)
23,216 11,957 10,310 1,172 475 223 35,396
Six months ended June 30, 2000(4)
Operating revenues 4,507 6,139 5,601 537 1 - 10,646
Intersegment revenues (1) 7 55 30 25 - (62) -
------ ------ ------ ----- ----- ------ ------
Total operating revenues 4,514 6,194 5,631 562 1 (62) 10,646
Net Income (Loss) 444 84 56 27 1 - 528
Total assets at June 30, 2000(3)
$22,124 $ 9,248 $ 6,853 $2,080 $315 $(143) $31,229
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(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, 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.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
PG&E Corporation is an energy-based holding company headquartered in San Francisco, California. PG&E Corporation's Northern and Central California energy utility subsidiary, Pacific Gas and Electric Company (the Utility), delivers electric service to approximately 4.6 million customers and natural gas service to approximately 3.8 million customers. On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. The factors causing the Utility to take this action are discussed in this Management's Discussion and Analysis (MD&A) and in Notes 2 and 3 of the Notes to the Condensed Consolidated Financial Statements.
PG&E Corporation's subsidiary, 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 Gas Transmission Northwest 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 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 the Consolidated Financial Statements incorporated by reference in their combined 2000 Annual Report on Form 10-K.
This combined Quarterly Report on Form 10-Q, including this MD&A, contains forward looking statements about the future that are necessarily subject to various risk and uncertainties. In addition, PG&E Corporation expects that its net income from operations for 2001 will be in the range of $2.70-$2.75 per share. Earnings from operations exclude items impacting comparability and should not be considered an alternative to net income or an indicator of a Company's operating performance. 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;
- the extent to which more information is revealed about the recently released California Department of Water Resources' revenue requirements and the impact such revenue requirements may have on the Utility's financial condition and results of operation;
- 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 under-collected wholesale power purchase costs may be collected from customers;
- any changes in the amount of transition costs the Utility is allowed to collect from its customers, and the timing of the completion of the Utility's transition cost recovery;
- future market prices for electricity and future fuel prices, which in part, are influenced by future weather conditions, the availability of hydroelectric power, and the development of competitive markets;
- the method and timing of valuation 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 riskssuch as PG&E NEG's failure to obtain financing, necessary permits or equipment, the failure of third-party contractors to perform their contractual obligations, the failure of equipment to perform as anticipated, or an inability to obtain equipment or labor on acceptable terms;
- 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.
In this MD&A, we first discuss the California energy crisis and its impact on our liquidity. We then discuss statements of cash flows and financial resources, and our results of operations for the three and six-month periods ended June 30, 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 under- collected 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 under-collected 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 political 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 and 3 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 18.2 cents per kilowatt-hour (kWh) for the seven-month period of June 2000 through December 2000, as compared to an average cost of 4.2 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 under-collection 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 the 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 paper, and had issued $1,240 million of floating rate notes.
In response to the growing crisis, on January 4, 2001, the California Public Utilities Commission (CPUC) approved an interim 1.0 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, LLC, 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 ended 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 for 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 additional 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. In February 2001, California Governor Gray Davis, acting under California's Emergency Services Act, commandeered the contracts valued at $243 million 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. The Utility has recently filed a complaint against the state to recover the value of the seized contracts.
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 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 amounts of power on the spot market at prevailing market prices.
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.) On February 14, 2001, the Federal Energy Regulatory Commission (FERC) ordered that the ISO could only buy power on behalf of creditworthy entities. The FERC order also stated that the ISO could continue to schedule power for the Utility as long as it comes from its own generation units and is routed over its own transmission lines. Despite the FERC orders, the ISO continued to bill the
Utility for the ISO's wholesale power purchases. 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. In light of the FERC's April 6, 2001 order, the Utility has not recorded any such estimated ISO charges after April 6, 2001, except for the ISO's grid management charge, although the Utility has accrued the full amount of the ISO charges up to April 6, 2001 in the accompanying financial statement. On June 13, 2001, the FERC denied the ISO's request for rehearing of its April 6, 2001 order.
The Utility has filed a complaint in 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. On June 26, 2001, the Bankruptcy Court issued a preliminary injunction prohibiting the ISO from charging the Utility for the 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 issuing the injunction, the Bankruptcy Court noted that the FERC orders permit the ISO to schedule transactions that involve either a creditworthy buyer or a creditworthy counterparty, but noted the existence of unresolved issues regarding how to ensure these creditworthiness requirements for real-time transactions and emergency dispatch orders issued by the ISO to power sellers. The Utility believes that its only responsibility for third party power delivered to its customers is to pay the DWR the amount collected from customers, whether the third party power is purchased by a creditworthy buyer or whether the purchase is facilitated by a creditworthy counterparty.
As a result of (1) the failure, at the time of filing, 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 under-collected 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.
Under Chapter 11, 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. Subsidiaries of the Utility, including PG&E Funding LLC (which holds Rate Reduction Bonds, discussed further in Note 2) and PG&E Holdings LLC (which holds stock of the Utility), are not included in the Utility's petition. The Utility's Consolidated Financial Statements have been prepared in accordance with the American Institute of Certified Public Accountants' Statement of Position 90-7 (SOP 90-7), "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code," and on a going concern basis, which contemplates continuity of operation, realization of assets and liquidation of liabilities in the ordinary course of business. However, as a result of the filing, such realization of assets, and liquidation of liabilities are subject to uncertainty.
Certain claims against the Utility in existence prior to the filing of the petition for relief are stayed while the Utility continues business operations as a debtor-in-possession. These claims are reflected in the June 30, 2001, balance sheet as "liabilities subject to compromise." Additional claims (liabilities subject to compromise) may arise subsequent to the filing date resulting from (1) negotiations; (2) rejection of executory contracts, including leases; (3) actions by the Bankruptcy Court; (4) further developments with respect to disputed claims; (5) proofs of claim; or (6) other events. Payment terms for these amounts will be established through the bankruptcy proceeding.
Claims secured against the Utility's assets ("secured claims") also are stayed, although the holders of such claims have the right to move the court for relief from the stay. Secured claims are secured primarily by liens on substantially all of the Utility's assets. The Bankruptcy Court has approved making the regular interest payments on the Utility's secured debt and by pledged accounts receivable from gas customers.
A creditors' committee has been appointed as an official committee and, in accordance with the provisions of the Bankruptcy Code, will have the right to be heard on all matters that come before the Bankruptcy Court. The Utility expects that the creditors' committee will play an important role in the negotiation of the terms of any plan of reorganization.
Since the filing, the Bankruptcy Court has approved various requests by the Utility to permit the Utility to carry on its normal business operations, and pay certain pre-petition obligations. Additionally, the Utility has secured approval for approximately $1.5 billion in capital expenditures for on-going business needs such as upgrading and improving transmission lines and substations. The Utility's current actions are intended to allow the Utility to continue to operate while the bankruptcy proceedings continue.
On January 10, 2001, the Utility suspended the payment of its fourth quarter 2000 common stock dividend of $110 million, declared in October 2000, to PG&E Corporation and its wholly owned subsidiary PG&E Holdings, LLC Until its financial condition is restored, the Utility is precluded from paying common stock dividends to PG&E Corporation and PG&E Holdings, LLC In addition, the Utility's Board of Directors did not declare the regular preferred stock dividends for the three-month period ended January 31, 2001, or for the three- month period ended April 30, 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.
In July 2001, the Bankruptcy Court granted a motion that the Utility had filed requesting that the court extend until December 6, 2001, the period during which the Utility has the exclusive right to file a plan of reorganization in its Chapter 11 case. Under the normal timeline, the exclusivity period would have ended on August 6, 2001, 120 days after the Utility's April 6, 2001, Chapter 11 filing. The Utility filed for an extension of the exclusivity period in the event that additional time is needed to continue discussions with creditors and to develop and file a comprehensive and feasible plan of reorganization. The Bankruptcy Court may confirm a plan of reorganization only upon making certain findings required by the Bankruptcy Code, and a plan may be confirmed over the dissent of non-accepting creditors and equity security holders if certain requirements of the Bankruptcy Code are met. The payment rights and other entitlements of pre-petition creditors and the Utility's shareholders may be substantially altered by any plan of reorganization confirmed by the Bankruptcy Court. Although it is the Utility's intent to pay all valid claims, pre- petition creditors may receive, under a plan, less than 100% of the face value of their claims, and the interests of the Utility's equity security holders may be affected. A plan of reorganization could materially change the amounts and classification reported in the consolidated financial statements.
The Utility is not able at this time to predict the outcome of its bankruptcy case, the terms and provisions of any plan of reorganization, or the effect of the Chapter 11 reorganization process on the claims of the creditors of the Utility or the interests of the Utility's preferred security holders. However, the Utility believes, based on information presently available to it, that cash available from operations will provide sufficient liquidity to allow it to continue as a going concern for the foreseeable future.
PG&E Corporation
The liquidity and financial condition crisis faced by the Utility also negatively impacted PG&E Corporation. Through December 31, 2000, PG&E Corporation funded its working capital needs primarily by drawing down on available lines of credit and other short-term credit facilities. At December 31, 2000, PG&E Corporation had borrowed $185 million against its five-year revolving credit agreement and had issued $746 million of commercial paper. Due to the credit ratings downgrades of PG&E Corporation, the banks refused any additional borrowing requests and terminated their remaining commitments under existing credit facilities. Commencing January 17, 2001, PG&E Corporation began to default on its maturing commercial paper obligations.
Commencing on March 2, 2001, PG&E Corporation refinanced its debt obligations with $1 billion in aggregate proceeds of two term loans under a common credit agreement with General Electric 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 $109 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.
PG&E Corporation itself had cash and short-term investments of $272 million at June 30, 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.
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 $697 million and $1,675 million for the six months ended June 30, 2001 and 2000, respectively. The decrease of $1,978 million between 2001 and 2000 is attributable to the California energy crisis previously discussed.
Cash used in investing activities was $1,065 million during the six months ended June 30, 2001, compared with $680 million used during the same period for 2000. In 2001, the primary use of cash for investing activities was $818 million for additions to property, plant, and equipment, compared with $670 million used for similar purposes in 2000.
Cash generated through financing activities for the six month ended June 30, 2001, was $152 million compared with $969 million used for the same period in 2000. A loan in 2001 netted $906 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 $969 million used in 2000 resulted from reduced borrowings of $482 million and a dividend payments of $217 million.
Utility
The following section discusses the Utility's significant cash flows from operating, investing, and financing activities for the six-month periods ended June 30, 2001.
Net cash provided by the Utility's operating activities totaled $843 million and $1,298 million for the six months ended June 30, 2001 and 2000, respectively. The decrease of $455 million between 2001 and 2000 is primarily attributable to higher cost of gas, offset by partial down payment of pre-petition obligations.
The primary uses of cash for investing activities are additions to property, plant, and equipment. The Utility's capital expenditures for the six-month ended June 30, 2001, was $575 million.
During the six months ended June 30, 2001, the Utility did not declare any preferred or common stock dividends, compared with a payment of dividends on its common stock of $250 million, for the six months ended June 30, 2000. The Utility has suspended payment of its common and preferred dividends due to its financial condition. 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, LLC
The Utility's long-term debt that either matured, was redeemed, or was repurchased during the six months ended June 30, 2001, totaled $252 million. Of this amount, $141 million related to the Utility's rate reduction bonds maturing, $93 million related to mortgage bonds maturing, and $18 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 credit facility, which was due to expire in November 2002. The unused portion of 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. At June 30, 2001, the Utility had drawn, and had outstanding $938 million under this facility to repay maturing commercial paper. In addition, the total defaulted commercial paper outstanding at June 30, 2001, formerly backed by both this and another,
now cancelled, facility, was $873 million.
There was no new long-term debt issued in the period ended June 30, 2001. In addition, there was no additional commercial paper issued during this same period.
As of August 1, 2001, the Utility is current with all interest and sinking fund payments on its mortgage bonds.
Due to the bankruptcy filing, the Utility is unable at this time to repay unsecured pre-petition creditors. The Utility has not made interest payments on the following unsecured debt: pollution control loan agreements, the 7.375% senior notes, the $1.24 billion floating rate notes, commercial paper, bank loan drawdowns, and other unsecured debt. Due to events of default under the credit agreements with letter of credit banks, in April and May 2001, four letter of credit banks accelerated and redeemed pollution control loans totaling $454 million. All of these redemptions were funded by the letter of credit banks resulting in like obligations from the Utility to the banks.
Four other banks have made the May 1, June 1, July 1 and August 1, 2001, interest payments on the $614 million principal amount of pollution control bonds backed by letters of credit. The bond insurance company has made the June 1, 2001, interest payment for the pollution control bond backed by bond insurance.
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. As of June 30, 2001, the Company Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures have been reclassified to liabilities subject to compromise on the Consolidated Balance Sheet.
PG&E National Energy Group
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. To date, PG&E NEG has made a number of commitments associated with the planned growth of owned and controlled generating facilities, as well as pipelines. These include commitments for projects under construction, commitments for the acquisition and maintenance of equipment needed for projects under development, payment commitments for tolling arrangements, and forward sale and purchase commitments associated with PG&E NEG's energy marketing and trading activities.
On May 22, 2001, PG&E NEG completed an offering of $1 billion in senior unsecured notes and received net proceeds after bond discount of approximately $987 million. PG&E NEG used a portion of the proceeds and intends to use the balance of the senior notes issuance, net of $13 million of bond issuance costs, to pay down existing revolving debt, fund investments in generating facilities and pipeline assets, working capital requirements, and other general corporate requirements. These Senior Notes have an aggregate principal amount of $1
billion, bear interest at 10.375% per annum, and mature on May 16, 2011.
In addition, PG&E Corporation historically has provided to the PG&E NEG credit support for a range of contractual commitments. With respect to generating facilities, this collateral has included agreements to infuse equity in specific projects when these projects begin operations or when a project that has been leased is purchased. PG&E Corporation also has provided guarantees of PG&E NEG obligations under several long-term tolling arrangements and as collateral for commitments under various energy trading contracts entered into by PG&E Energy operations to provide short-term collateral to conterparties. As of June 30, 2001, except for $108 million of guarantees relating to various energy trading master contracts, all PG&E Corporation equity infusion agreements and guarantees have been replaced with PG&E NEG equity infusion agreements, guarantees or other forms of security.
In connection with the replacement of PG&E Corporation guarantees with PG&E NEG guarantees, and with the continued growth of energy trading and marketing positions, the PG&E NEG has experienced a substantial increase in the amount of cash it has been required to place on deposit with various counterparties without a commensurate increase in margin deposits received from counterparties. The cash margin deposits outstanding to counterparties net of cash margin received from counterparties increased from $10 million as of December 31, 2000 to $92 million as of June 30, 2001. On June 15, 2001, PG&E NEG established a $550 million revolving credit facility (which includes the ability to issue letters of credit) with a syndicate of banks. This new $550 million facility has an initial 364-day term that expires on June 14, 2002.
During the six months ended June 30, 2001, PG&E NEG generated net cash of $19 million in operating activities. Net cash from operating activities before changes in other working capital accounts was $39 million, primarily driven by net income. Net cash outflow related to certain other working capital accounts was $20 million, driven primarily by an increase in margin deposits related to PG&E NEG's trading activities.
During the six months ended June 30, 2001, PG&E NEG used net cash of $523 million in investing activities. PG&E NEG's cash outflows from investing activities were primarily attributable to capital expenditures on generating projects in construction, turbine prepayments, and advanced development.
Net cash generated by financing activities was $567 million for the six months ended June 30, 2001 principally from the net proceeds related to the senior notes.
RESULTS OF OPERATIONS
The table shows for the three- and six-months ended June 30, 2001 and 2000, certain items from the 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 this group.) The information for PG&E Corporation (the "Total" column) includes the appropriate intercompany
elimination. Following this table we discuss our results of operations.
PG&E National Energy Group
-------------------------------------------
PG&E
Integrated Interstate Corporation
Energy and Pipeline NEG & Other
(in millions) Utility Total NEG Marketing Operations Eliminations Elimination(1) Total
------ -------- --------- --------- ------------ ------------- -------
Three months ended June 30, 2001
Operating revenues $2,309 $2,756 $2,679 $ 64 $13 $ (52) $ 5,013
Operating expenses 973 2,631 2,598 25 8 (38) 3,566
Operating income 1,447
Reorganization interest income 32
Interest income 42
Interest expense (312)
Other income (expenses), net 4
Income taxes 463
Net income 750
Net cash provided by operating activities 15
Net cash used by investing activities 566
Net cash provided by financing activities 584
EBITDA (2) 1,550 163 108 49 6 (3) 1,710
Three months ended June 30, 2000(3)
Operating revenues 2,296 3,362 3,090 280 (8) (20) 5,638
Operating expenses 1,744 3,280 3,060 229 (9) (8) 5,016
Operating income 622
Interest income 26
Interest expense (182)
Other income (expenses), net (14)
Income taxes 204
Net income 248
Net cash provided by operating activities 613
Net cash used by investing activities (440)
Net cash used by financing activities (126)
EBITDA (2) 602 111 52 58 1 (36) 677
Six months ended June 30, 2001
Operating revenues 4,871 6,964 6,831 129 4 (147) 11,688
Operating expenses 4,955 6,754 6,697 50 7 (128) 11,581
Operating income 107
Reorganization interest income 32
Interest income 77
Interest expense (559)
Other income (expenses), net (5)
Income taxes (147)
Net income (201)
Net cash provided by operating activities 697
Net cash used by investing activities (1,065)
Net cash provided by financing activities 152
EBITDA (2) 337 291 192 99 - (12) 648
Six months ended June 30, 2000(3)
Operating revenues 4,514 6,194 5,631 562 1 (62) 10,646
Operating expenses 3,392 6,002 5,541 460 1 (46) 9,348
Operating income 1,298
Interest income 50
Interest expense (365)
Other income (expenses), net (23)
Income taxes 432
Net income 528
Net cash provided by operating activities 1,675
Net cash used by investing activities (680)
Net cash used by financing activities (969)
EBITDA (2) $1,472 $ 253 $ 137 $116 $ - $ (34) $ 1,691
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(1) Net income on inter-company positions recognized by segments using mark-to- market accounting is eliminated. Inter-company transactions are also eliminated.
(2) EBITDA is defined as income before provision for income taxes, interest expense, interest income, depreciation and amortization. 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 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 7 of the Notes to the Condensed Consolidated Financial Statements).
Overall 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 and 3 of the Notes to the Condensed Consolidated Financial Statements for more information on the California energy crisis.
PG&E Corporation's net income for the second quarter ended June 30, 2001 was $750 million, compared to net income of $248 million for the same period in 2000, representing an increase of $502 million. The Utility's net income available for common stock for the quarter ended June 30, 2001 accounted for $480 million of the increase.
PG&E Corporation incurred a net loss of $201 million for the six-month period ended June 30, 2001 compared to net income of $528 million for the same period in 2000. Of the $729 million net decrease from the prior six-month period in 2000, the Utility was responsible for virtually all of the decrease, somewhat offset by an increase in net income at PG&E NEG.
Subject to final resolution of regulatory and judicial matters, PG&E Corporation and the Utility expect future earnings to continue to reflect increased volatility as a result of no longer being able to reflect the impact of generation-related regulatory balancing accounts in their financial statements. As previously discussed, the Utility cannot meet the accounting probability standard required to defer generation costs for future recovery. As such, costs and revenues historically deferred in regulatory balancing accounts now directly impact net income. The Utility's net income will be impacted by changes in electricity and gas costs, customer demand, weather, costs of operations, conservation and other related items.
The changes in performance for the three and six-month periods ended June 30, 2001 and 2000 are generally attributable to the following factors:
- The Utility's earnings were impacted as a result of its under-collected purchased power costs. Because of the lack of a regulatory, legislative, or judicial solution to the California energy crisis, the Utility cannot defer for future recovery its under-collected purchased power costs. These costs have been expensed as incurred. For the six-month period ended June 30, 2001, the total under-collected purchased power costs were $563 million, after-tax of which $8 million, pre-tax are professional fees and expenses and reflected within the reorganization sections of the consolidated statement of operations. During the second quarter of 2001, the Utility recognized after- tax offsets of $552 million against previously expensed purchased power costs. These offsets included $327 million related to the market value of terminated bilateral contracts and $155 million of adjustments to first quarter estimates of ISO costs. The adjusted ISO costs resulted from actual billings received in May 2001 for costs incurred in March 2001.
- As a result of the high cost of power, with no offsetting revenues, the Utility and PG&E Corporation have a net loss for California tax purposes through June 30, 2001. California law does not permit carrybacks of such losses, and only permits carryforwards of 55% of such losses. As a result, for the six-month period ended June 30, 2001, PG&E Corporation was unable to recognize $8 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's financial position. The incremental cost
of these borrowings was $61 million, after-tax, for the quarter ended June 30, 2001, and $103 million, after-tax, for the six-month period ended June 30, 2001.
- The Utility's filing of a petition of reorganization under Chapter 11 of the U.S. Bankruptcy Code has resulted in incremental external financial and legal expenses associated with the development of a plan of reorganization. For the quarter ended June 30, 2001, these fees amounted to $9 million after- tax of which $8 million, pre-tax, are professional fees and expenses reflected within the reorganization section in the consolidated statement of operations. For the six-month period ended June 30, 2001, total incremental external financial and legal fees were $25 million after-tax.
- PG&E NEG increased earnings by $34 million for the three-month period ended June 30, 2001, over the same period in 2000. The increase was a result of the impact of favorable market movements on merchant generating plants and increased pipeline utilization in the Pacific Northwest.
Dividends
PG&E Corporation's historical quarterly common stock dividend was $0.30 per common share, which corresponded to an annualized dividend of $1.20 per common share.
On January 10, 2001, the Board of Directors of PG&E Corporation suspended the payment of its fourth quarter 2000 common stock dividend of $0.30 per share declared by the Board of Directors on October 18, 2000 and payable on January 15, 2001 to shareholders of record as of December 15, 2000. The California energy crisis had created a liquidity crisis for PG&E Corporation, which led to the suspension of payments of dividends to conserve cash resources. These defaulted dividends were later paid on March 2, 2001 in conjunction with the refinancing of PG&E Corporation obligations, discussed above under the Liquidity and Financial Resources section.
Additionally, the parent company refinancing agreements mentioned above prohibit dividends from being declared or paid until the term loans have been repaid. The agreement is for a term of two years with an option on behalf of PG&E Corporation to extend the term for an additional year.
On January 10, 2001, the Utility suspended the payment of its fourth quarter 2000 common stock dividend of $110 million, declared in October 2000, to PG&E Corporation and its wholly owned subsidiary PG&E Holdings, LLC Until its financial condition is restored, the Utility is precluded from paying dividends to PG&E Corporation and PG&E Holdings, LLC
Utility
The Utility's net income was $696 million for the quarter ended June 30, 2001, compared to $216 million for the same period in 2000. This increase in net income was primarily the result of the recognition of the market value of terminated bilateral contracts and the change in the amount of ISO accruals for purchased power costs.
The Utility had a net loss of $304 million for the six-month period ended June 30, 2001, compared to the prior year's net income of $444 million. The change in earnings was primarily the result of the $.9 billion charge to earnings for under-collected purchased power costs in excess of the amounts provided in
customer rates for recovery of such costs. The under-collected amounts include ISO charges incurred between January 1 and April 6, 2001. Generally accepted accounting principles require that the amounts be accounted for as expenses unless they can be deemed probable of recovery through the regulated rates. Due to uncertainty created by the energy crisis, the Utility cannot meet the accounting probability standard. This charge was partially offset by the recognition of the value of the terminated bilateral contracts.
Operating income was $1,336 million for the second quarter ended June 30, 2001, compared to operating income of $552 million for the same period in 2000. This increase in operating income is primarily attributable to the recognition of the value of the terminated bilateral contracts worth $552 million and the change in the amount of the ISO accruals for purchased power costs.
The Utility had an operating loss of $84 million for the six months ended June 30, 2001, compared to operating income of $1,122 million for the same period in 2000. This change is due to the charge to earnings for under-collected purchased power costs, as discussed above, which was partially offset by the recognition of the value of the terminated bilateral contracts.
The Utility's operating revenues for the three months ended June 30 were $2.3 billion in both 2001 and 2000. Electric revenues decreased by $304 million for the three months ended June 30, 2001, primarily due to the reduction of revenue resulting from a portion of the Utility's billed revenues being passed through to the DWR for the DWR'S electricity purchases which was partially offset by an increase in customer revenues. Beginning in April 2001, the DWR began supplying electric power to the Utility's customers in excess of that power generated by or contracted for by the Utility. The Utility acts solely as a billing agent for the DWR. Therefore, the amounts paid to the DWR for deliveries are not recorded as expense and the revenue billed by the Utility to its customers associated with this energy is excluded from revenues.
Gas revenues increased $317 million for the three months ended June 30, 2001, due to the increased revenues from commercial and residential customers due to higher gas costs resulting from high natural gas prices. Such costs are passed on directly to customers.
The Utility's operating revenues for the six months ended June 30, 2001 were $4.9 billion compared to operating revenues of $4.5 billion for the same period in 2000. Gas revenues increased $1,003 million while electric revenues decreased $646 million. The increase in gas revenues was primarily due to increased revenues from residential and commercial customers due to higher average cost of gas resulting from higher natural gas prices and increased usage during 2001.
The decrease in electric revenues of $646 million was primarily due to credits issued to direct access customers and due to the reduction of revenue resulting from a portion of the Utility's billed revenues being passed through to the DWR for the DWR's electricity purchases. As discussed above, these revenues are not included in the Utility's reported revenues.
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 generation price multiplied by customer energy usage for the period, with the customer being obligated to their ESP at their direct access contract rate.
For the six-month period ended June 30, 2001, the estimated total of accumulated credits for direct access customers that have not been paid by the Utility is approximately $354 million. Such amounts are reflected on the Utility's condensed consolidated balance sheet. The actual amount that will be refunded to ESPs or directly to the customer will be dependent upon the outcome of the Utility's bankruptcy proceeding, when the rate freeze ends, and whether there are any adjustments made to wholesale energy prices by FERC.
The table below summarizes the changes in the Utility's operating expenses:
Three months
ended June 30
------------------
Percentage
Increase Increase
(in millions) 2001 2000 (Decrease) (Decrease)
------- ------- -------- ----------
Cost of electric energy $ (362) $ 975 $ (1,337) (137) %
Cost of gas 429 182 247 136 %
Operating and maintenance 676 543 133 24 %
Depreciation, amortization, and decommissioning 222 44 178 405 %
Reorganization professional fees and expenses 8 - 8 -
---- ---- ----- ----
Total operating expenses $ 973 $ 1,744 $ (771) (44) %
==== ===== ===== ====
Six months Increase Increase
ended June 30 (Decrease) (Decrease)
------------------ -------- ----------
2001 2000
------- -------
Cost of electric energy $ 1,955 $ 1,488 $ 467 31 %
Cost of gas 1,345 465 880 189 %
Operating and maintenance 1,208 1,094 114 10 %
Depreciation, amortization, and decommissioning 439 345 94 27 %
Reorganization professional fees and expenses 8 - 8 -
---- ---- ----- ----
Total operating expenses $ 4,955 $ 3,392 $ 1,563 46 %
==== ===== ===== ====
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The cost of electric energy decreased by $1,337 million for the three months ended June 30, 2001 compared to the same period in 2000. This was attributable to the recognition of the market value of several electric bilateral contract terminations amounting to $552 million, a $261 million change in the amount of the ISO related costs previously accrued and the impact of the fact that costs of electric energy procured by the DWR are no longer reflected by the Utility. In accordance with state legislation, the Utility does not take title to the energy procured by the DWR for delivery to its customers. Rather, the Utility acts solely as a billing agent for the DWR. Therefore, the amounts paid to the DWR for deliveries are not recorded as expense and the revenue billed by the Utility to its customers associated with this energy is excluded from revenues.
The cost of electric energy increased by $467 million for the six months ended June 30, 2001 compared to the same period in 2000. This was attributable to the higher average cost of electricity in 2001. Historically, the Utility generally
would have deferred such under-collected purchased power costs as a regulatory asset to be collected from customers in future rates. However, due to the lack of regulatory, legislative, or judicial relief, the Utility cannot conclude that it is probable that its under-collected purchase power costs will be collected in future rates. Therefore, in 2001 such costs are being expensed as incurred.
The higher costs were offset, in part, by the recognition of the market value of electric bilateral contract terminations and the costs being passed through to the DWR for the DWR's electricity purchases, as discussed above.
The cost of gas increased by $247 million and $880 million for the three months and six months ended June 30, 2001, respectively, compared to the same periods in 2000. The average cost of gas was $7.80 per decatherm (DTh) for the six months ended June 30, 2001 compared to $2.59 per DTh for the same period in the prior year. The procurement costs for gas are passed directly onto the customers.
The Utility's operating and maintenance expenses increased $133 million in the three-month period, and $114 million in the six-month period ending June 30, 2001 compared to the same periods in 2000. These increases are a result of a Diablo Canyon refueling outage with no such outage in the similar periods of 2000, increased customer energy efficiency expenses and higher franchise requirements fees resulting from higher electric and gas revenue.
Depreciation, amortization, and decommissioning increased by $178 million in the three-month period, and $94 million in the six-month period ending June 30, 2001 compared to the same periods in 2000. These increases are due to the elimination of regulatory asset deferrals for generation-related transition costs in 2001. In 2000, when generation-related regulatory assets were amortized to depreciation, amortization and decommissioning expense and when purchased power costs were under-collected, the Utility would defer the under- collections by reducing depreciation, amortization and decommissioning expense. Since the Utility wrote off its generation-related regulatory assets and under- collected purchased power costs in 2000 and continues to expense as incurred its under-collected purchased power costs in 2001, no such deferral and reduction to depreciation, amortization, and decommissioning expense occurs in 2001.
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, LLC
PG&E National Energy Group
Operating income at PG&E NEG was $125 million for the second quarter ended June 30, 2001 compared to $82 million for the same period in 2000. For the six-month period ended June 30, 2001, operating income was $210 million, compared to $192 million for the same period in 2000.
Operating revenues were $2.8 billion in the three months ended June 30, 2001, a decrease of $.7 billion, or 21%, from the three months ended June 30, 2000.
Operating revenues for PG&E Energy decreased by $.5 billion, or 17% primarily as the result of decreased commodity sales and a decline in the market value of long-term gas transportation contracts. Operating revenues for PG&E Pipeline decreased by $216 million. Short-term firm revenues earned by PG&E Pipeline operations increased, resulting from higher usage and higher negotiated rates. However, these increases were offset by the completion of the sale of PG&E GTT in late 2000, which had revenues of $224 million for the three months ended June 30, 2000.
Operating revenues were $7.0 billion in the six months ended June 30, 2001, an increase of $.3 billion, or 4%, from the six months ended June 30, 2000. Operating revenues for PG&E Energy increased by $.7 billion as a result of increases in the price of power and gas, and a focus of trading efforts on asset management and higher-margin trades. These increases were partially offset by decreases in commodity sales and declines in the market value of long-term gas transportation contracts during the second quarter. Operating revenues for PG&E Pipeline decreased by $433 million. Short-term firm revenues earned by pipeline increased, resulting from higher usage and higher negotiated rates. These increases were offset by the completion of the sale of PG&E GTT in late 2000, which had revenues of $449 million for the six months ended June 30, 2000.
Operating expenses were $2.6 billion in the three months ended June 30, 2001, a decrease of $.8 billion, or 23%, from the three months ended June 30, 2000. The decrease primarily resulted from the lower quantity of PG&E Energy commodity sales, overall reduced operational costs at our facilities, and the reduction of costs associated with the sale of PG&E GTT in late 2000 from PG&E Pipeline segment.
Operating expenses were $6.8 billion in the six months ended June 30, 2001, an increase of $.3 billion, or 4%, from the six months ended June 30, 2000. The increase primarily resulted from higher costs of commodities and fuel in the PG&E Energy segment, partially offset by overall reduced operational costs at PG&E NEG facilities, and the reduction of costs as a result of the sale of PG&E GTT in late 2000.
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.
In March 2000, two interveners filed applications for rehearing of the Utility's 1999 GRC decision, alleging that the CPUC committed legal errors by approving funding in certain areas that were not adequately supported by record evidence. In April 2000, the Utility filed its response to these applications for rehearing, defending the GRC decision against the allegations of error. A CPUC decision on the applications for rehearing is pending.
In the 1999 GRC decision, the CPUC ordered that the Utility file a 2002 GRC. As a result of the current energy crisis, the procedural schedule has been delayed pending the CPUC's resolution of the Utility's request that it be permitted to file an alternative schedule or an alternative to the 2002 GRC. An earlier decision initially delaying the schedule affirms that rates would still become effective on January 1, 2002, although the CPUC decision may not be rendered until after that date.
Order Instituting Investigation (OII) into Holding Company Activities
On April 3, 2001, the CPUC issued an order instituting an investigation into
whether the California investor-owned utilities, including the Utility, have
complied with past CPUC decisions, rules, or orders authorizing their holding
company formations and/or governing affiliate transactions, as well as
applicable statutes. The order states that the CPUC will investigate (1) the
Utilities' transfer of money to their holding companies since deregulation of
the electric industry commenced, including during times when their utility
subsidiaries were experiencing financial difficulties; (2) the failure of the
holding companies to financially assist the utilities when needed; (3) the
transfer, by the holding companies, of assets to unregulated subsidiaries; and
(4) the holding companies' action to "ringfence" their unregulated subsidiaries.
The CPUC will also determine whether additional rules, conditions, or changes
are needed to adequately protect ratepayers and the public from dangers of abuse
stemming from the holding company structure. The CPUC will investigate whether
it should modify, change, or add conditions to the holding company decisions,
make further changes to the holding company structure, alter the standards under
which the CPUC determines whether to authorize the formation of holding
companies, otherwise modify the decisions, or recommend statutory changes to the
California Legislature. As a result of the investigation, the CPUC may impose
remedies (including penalties), prospective rules, or conditions, as
appropriate.
PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. As described above, on April 6, 2001, the Utility filed a voluntary petition for relief 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.
On May 14, 2001, the CPUC issued an interim decision that recategorized the proceeding from quasi-legislative to the ratesetting category because the ratesetting category is most appropriate for mixed factual and policy proceedings. In addition, the CPUC noted that the proceeding may be recategorized as adjudicatory at a later time if the CPUC finds that the Utility violated prior decisions and other laws. On June 14, 2001, the CPUC denied the Utility's request for rehearing of the interim decision placing this proceeding in the ratesetting category.
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 could not 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. The Utility believes that ORA's recommendations are unjustified and challenged those recommendations in hearings in June 2001.
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% preferred stock, and 48% common equity. In March 2001, the CPUC issued a proposed decision recommending no change to the current 11.22% ROE for test year 2001. This authorized ROE results in a corresponding 9.12% return on rate base and no change in the Utility's electric or gas revenue requirement for 2001. A final CPUC decision is 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. 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 July 2001, the FERC approved another settlement that permits, the Utility to collect $251 million 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 paid to the Utility from the ISO for congestion management charges 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. In this filing, the Utility estimates that if FERC grants its request, it will collect from Western an additional $1,125 million 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 6 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 June 30, 2001, the Utility expects to spend $306 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 $459 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 $306 million and $320 million at June 30, 2001 and December 31, 2000, respectively. The $306 million accrued at June 30, 2001 includes (1) $139 million related to the pre-closing remediation liability, associated with divested generation facilities (see further discussion in the "Generation Valuation " section of Note 2 of the Notes to the Condensed Consolidated Financial Statements), and (2) $167 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 $306 million environmental remediation liability, the Utility has recovered $139 million through rates, and expects to recover another $86 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.
On June 28, 2001 the Bankruptcy Court entered its "Order on Debtor's Motion for Authority to Continue Its Hazardous Substances Cleanup Program". The Utility is authorized to expend (i) up to $22 million in each calendar year in which this Chapter 11 case is pending to continue its hazardous substance remediation programs and procedures, and (ii) any additional amounts necessary in emergency situations involving post-petition releases or threatened releases of hazardous substances, if such excess expenditures is necessary in the Utility's reasonable business judgment to prevent imminent harm to public health and safety or the environment (provided that the Utility seeks the Court's approval of such emergency expenditures at the earliest practicable time), in each case as described in the motion.
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) has been conducting a nationwide enforcement investigation regarding the historical compliance of coal-fueled electric generating stations with various permitting requirements of the Clean Air Act. Specifically, the EPA and the U.S. Department of Justice have recently 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, the EPA visited both facilities. PG&E NEG believes this request for information is part of the EPA's industry-wide investigation of coal-fired power plants' compliance with the Clean Air Act requirements governing plant modifications. PG&E NEG also believes that any changes it made to these plants were routine maintenance or repair and, therefore, did not require permits. The EPA has not issued a notice of violation or filed any enforcement action against PG&E NEG at this time. Nevertheless, if the EPA disagrees with PG&E NEG's conclusions with respect to the changes PG&E NEG 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.
From time to time various states in which our facilities are located consider the adoption of air emissions standards that may be more stringent than those imposed by the EPA. On May 11, 2001, the Massachusetts Department of Environmental Protection (DEP) issued regulations imposing new restrictions on emissions of NOx and SO2, mercury and carbon dioxide from existing coal-fired power plants. These restrictions will impose more stringent annual and monthly limits on NOx and SO2 emissions than currently exist and will take effect in stages, beginning in October 2004 if no permits are needed for the changes necessary to comply, and beginning in 2006 if such permits are needed. The DEP has informed PG&E NEG that, based upon its current understanding of the facilities' plans for compliance with the new regulations, it believes that permits will be needed and that the initial compliance date will therefore by 2006. However, the need for permits triggers an obligation to meet Best Available Control Technology (BACT) requirements. Compliance with BACT at the facilities could require implementation of controls beyond those otherwise necessary to meet the emissions standards in the new regulations. Mercury emissions are capped as a first step and must be reduced by October 2006 pursuant to standards to be developed. Carbon dioxide emissions are regulated for the first time and must be reduced from recent historical levels. PG&E NEG believes that compliance with the carbon dioxide caps can be achieved through implementation of a number of strategies, including sequestrations and offsite reductions. Various testing and recordkeeping requirements are also imposed.
By 2002, PG&E NEG plans to have approximately 5,100 MW of generating capacity in operation in New England. The new Massachusetts regulations affect primarily its Brayton Point and Salem Harbor generating facilities, representing approximately 2,300 MW. Through 2006, it may be necessary to spend
approximately $265 million to comply with these regulations. In addition, with respect to approximately 600 MW (or about 12%) of PG&E NEG's New England capacity, PG&E NEG may need to implement fuel conversion, limit operations, or install additional environmental controls. These new regulations require that PG&E NEG achieve specified emission levels earlier than the dates included in a previous Massachusetts initiative to which it had agreed.
The Federal Clean Water Act generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency and/or the EPA. All of the facilities that are required to have such permits either have them or have timely applied for extensions of expired permits and are operating in substantial compliance with the prior permit. At this time, three of the fossil-fuel plants owned and operated by an affiliate of PG&E NEG USGen New England, Inc. (Manchester Street, Brayton Point and Salem Harbor stations) are operating pursuant to permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and PG&E NEG anticipates 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 USGen New England's cost to comply with new permit conditions could be approximately $60 million through 2005. It is possible that the new permits may contain more stringent limitations than the prior permit.
PG&E NEG anticipates spending up to approximately $330 million, net of insurance proceeds, through 2006 for environmental compliance at currently operating facilities, which primarily addresses: (a) new Massachusetts air regulations made public on April 23, 2001 affecting the Brayton Point and Salem Harbor Stations; (b) wastewater permitting requirements that may apply to the Brayton Point, Salem Harbor and Manchester Street Stations; and (c) requirements, to which PG&E NEG agreed, that are reflected in a consent decree concerning wastewater treatment facilities at the Salem Harbor and Brayton Point Stations.
During April 2000, an environmental group served USGen New England, Inc., and other subsidiaries with a notice of its intent to file a citizen's suit under RCRA. The group stated that it planned to allege that USGen New England, Inc. as the generator of fossil fuel combustion wastes at Salem Harbor and Brayton Point, has contributed and is contributing to the past and present handling, storage, treatment and disposal of wastes at those facilities which may present an imminent and substantial endangerment to the public health or the environment. During September 2000, USGen New England, Inc. signed a series of agreements with the Massachusetts Department of Environmental Protection and the environmental group that address and resolve these matters. The agreements, which have been filed in federal court and are now incorporated in a consent decree, require, among other things, that USGen New England, Inc. alter its existing wastewater treatment facilities at both 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 cost of these activities is expected to be approximately $21 million, and they are underway.
PRICE RISK MANAGEMENT ACTIVITIES
PG&E Corporation and its subsidiaries have established risk management policies that allow 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 non-trading (hedging) purposes primarily to offset our primary market risk exposures, which include commodity price risk, interest rate risk, and foreign currency risk. We also
use derivatives, including those used for trading (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 either not hedged or only partially hedged) often exist due to ownership of physical assets (such as power plants, gas pipelines, etc.) and the obligation to serve customers. Net open positions may also be established based on the assessment of market conditions, business objectives, and risk tolerance limits set by management. To the extent that PG&E Corporation and its subsidiaries have an open position, they are exposed to the risk that fluctuating commodity prices, interest rates, and foreign currency exchange rates may adversely impact their financial results.
PG&E Corporation and its subsidiaries 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
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. Because of different regulatory incentives and rate-making methods, the Utility reports its commodity price risk separately for its electricity and natural gas businesses. Price risk management strategies primarily 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 electricity and natural gas loads. 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.
Utility Electric Commodity Price Risk
The Utility has had a very limited ability to enter into forward contracts to hedge their exposure to commodity price fluctuations because of the reluctance of counterparties to extend credit. As the Utility's credit rating dropped below investment grade in January 2001, the DWR began purchasing wholesale power for electric customers on behalf of the State of California. In February 2001, because the Utility was unable to make payment to the PX for existing power purchases, the PX sought to liquidate the Utility's remaining block-forward
contracts. Before they could do so, the PX block-forward contracts were seized by California Governor Gray Davis for the benefit of the State, acting under California's Emergency Services Act. As a result of continued increasing purchased power costs in excess of revenues from customers and lack of solutions to the energy crises, on April 6, 2001, the Utility sought protection from its creditors through a Chapter 11 bankruptcy filing. Many existing bilateral contracts were terminated in the first and second quarter of 2001 due to the downgrade of the Utility's credit rating and its subsequent bankruptcy filing. As explained in Note 2 of the Notes to the Condensed Consolidated Financial Statements, the Utility believes that it is no longer responsible for purchases made by DWR to meet the Utility's net open position. The Utility is currently paying DWR the amount of money it collects in retail rates for electricity (that is, excluding transmission, distribution, and other costs). The Utility believes that it is only obligated to pass through the amount it collects in electricity rates, and therefore, there is no price risk for electricity purchases to serve the net open position.
Although responsibility for the net open position currently lies with the DWR, it is anticipated that this responsibility will be transferred back to the Utility at an unknown future date. As explained in Note 2 of the Notes to the Condensed Consolidated Financial Statements, the Utility believes that the conditions required to end the rate freeze on retail electricity rates were met in 2000, after which time power purchase costs would be included in retail electricity rates. Electricity commodity price risks after the rate freeze ends would depend on how retail rates are determined. If traditional cost-of-service ratemaking methods are used, electricity commodity price risks would not have a material impact on PG&E Corporation's financial results.
Utility Natural Gas Commodity Price Risk
Under a rate-making method called the Core Procurement Incentive Mechanism (CPIM), the Utility recovers in retail rates the cost of procuring natural gas for its customers as long as the costs are within a 99% to 102% "dead-band" of a benchmark price. The benchmark price reflects a weighting of spot and forward gas prices that are representative of Utility gas purchases. Ratepayers and shareholders share costs or savings outside the dead-band equally. In addition, the Utility has contracts for capacity on the Transwestern gas pipeline. There is price risk related to the Transwestern gas pipeline to the extent that unused portions of the pipeline are brokered at floating rates.
Under a ratemaking method called the Gas Accord, shareholders are at risk for any revenues from the sale of capacity on the Utility's pipelines and gas storage fields held by the California Gas Transmission (CGT) business unit. The Utility is generally exposed to reduced revenues when price spreads narrow, although this exposure is mitigated through forward contracts.
PG&E NEG Commodity Price Risk
PG&E NEG is exposed to commodity price risk of its portfolio of electric generation assets and supply contracts that serve wholesale and industrial customers, in addition to various merchant plants currently in development. PG&E NEG manages such risks using a cost effective risk management program that primarily includes the buying and selling of fixed-price commodity commitments to lock in future cash flows of their forecasted generation. PG&E NEG is also exposed to commodity price risk of net open positions within their trading portfolio due to the assessment of and response to changing market conditions.
PG&E Corporation and its subsidiaries 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 instruments in our trading and non-trading portfolios and only derivative commodity instruments for PG&E NEG's non-trading portfolio (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 and its subsidiaries portfolios will incur a loss in one day greater than its value-at-risk.
The Utility's daily value-at-risk commodity price risk exposure for non-trading activities as of June 30, 2001, was $11 million for its natural gas business. The Utility believes that there is currently no commodity price risk associated with fluctuating electric power prices, because these costs should be fully reflected in future retail rates.
PG&E NEG's daily value-at-risk commodity price risk exposure as of June 30, 2001, was $15 million for trading activities and $36 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. Value-at-risk also does not reflect the significant regulatory, legislative, and legal risks currently facing the Utility due to the Utility's bankruptcy proceedings and the current California energy crisis.
Interest Rate Risk
PG&E Corporation is exposed to changes in interest rates primarily as a result of its variable rate commercial paper, bonds, bank loans, floating rate notes, project financing, and investing activities. In addition, PG&E Corporation is exposed to changes in interest rates on interest accruing on loan payments and trade payables currently in default. For a complete discussion of the risk management strategies and financial instruments used to manage interest rate risk, see PG&E Corporation's 2000 Annual Report on Form 10-K. PG&E Corporation uses sensitivity analysis to measure its interest rate price risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. As of June 30, 2001, if interest rates had averaged 1% higher, PG&E Corporation's earnings would have decreased by approximately $17 million.
Foreign Currency Risk
PG&E Corporation is exposed to foreign currency risk associated with the Canadian dollar. For a complete discussion of the risk management strategies and financial instruments used to manage foreign currency risk, see PG&E Corporation's 2000 Annual Report on Form 10-K. PG&E Corporation uses sensitivity analysis to measure its foreign currency exchange rate exposure to the Canadian dollar. As of June 30, 2001, if the Canadian dollar experienced a 10% devaluation, estimated losses would not have had a material impact on 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 6 of the Notes to the Condensed Consolidated Financial Statements for further discussion of significant pending legal matters.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PG&E Corporation's and Pacific Gas and Electric Company's primary market risk results from changes in energy prices and interest rates. We engage in price risk management activities for both trading and non-trading purposes. Additionally, we may engage in trading and non-trading activities using forwards, 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.)
PART 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 11 of the United States Bankruptcy Code. Bankruptcy law imposes an automatic stay to prevent parties from making certain claims or taking certain actions that would interfere with the estate or property of a Chapter 11 debtor. In general, the Utility may not pay pre- petition debts without the Bankruptcy Court's permission. Under the Bankruptcy Code, the Utility has the right to reject or assume executory contracts (contracts that require future performance). The last day for non-governmental unit creditors to file proofs of claim is September 5, 2001 and the last day for government entities to file proof of claims is October 3, 2001.
Since the filing, the Bankruptcy Court has approved various requests by the Utility to permit the Utility to carry on its normal business operations and to pay certain pre-petition obligations. For a discussion of some of these proceedings see the Quarterly Report on Form 10-Q filed by PG&E Corporation and Pacific Gas and Electric Company for the quarter ended March 31, 2001. More recently, the Bankruptcy Court has approved the Utility's assumption of various hydroelectric contracts with water agencies and irrigation districts, the implementation of a management retention program, and the continuation of environmental remediation and capital expenditure programs. Other recent proceedings are discussed below.
On May 18, 2001, the Bankruptcy Court vacated the United States Trustee's appointment of a ratepayers' committee finding that the Bankruptcy Code does not authorize the creation of such a committee. Under the Bankruptcy Code, only creditors and equity security holders are eligible for appointment to a committee by the U.S. Trustee. The Bankruptcy Court noted that 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. On July 10, 2001, the Bankruptcy Court denied the U.S. Trustee's motion to reconsider its earlier order.
On June 1, 2001, the Bankruptcy Court issued a decision denying the Utility's request for an injunction against the California Public Utilities Commission (CPUC) and its Commissioners to prohibit the implementation or enforcement of the CPUC's March 27, 2001 decision adopting changes to the transition period accounting mechanisms. The Court also granted the CPUC's motion to dismiss the complaint. Although the Court held that the Eleventh Amendment to the U.S. Constitution did not bar the Utility's suit against the individual Commissioners, the Court concluded that the Utility was not entitled to a stay or an injunction to prevent implementation and enforcement of the regulatory accounting order. First, the Court held that, assuming the Bankruptcy Code provision imposing an automatic stay on pre-petition proceedings might ordinarily apply (an issue that the Court expressly declined to decide), the Court determined that the Commissioners were acting pursuant to their police and regulatory power when issuing the order. Accordingly, the Court found that the order was exempt from the automatic stay provision pursuant to a statutory exemption for the commencement or continuation of an action or proceeding by a governmental unit to enforce such governmental unit's police and regulatory
power. Second, the Court held that the Utility had not shown any actual or threatened violation of federal law sufficient to warrant injunctive relief, nor did the balance of equities favor an injunction. The Utility's application for rehearing of the CPUC's decision remains pending at the CPUC. The Utility has initiated an appeal of the Bankruptcy Court's decision to the United States District Court for the Northern District of California, and the CPUC and its Commissioners have initiated a cross-appeal, both of which are pending.
The first meeting of creditors was held as scheduled on June 7, 2001. Senior executives of the Utility made themselves available to respond to questions from the U.S. Trustee and participating creditors about the Utility's assets, liabilities and administration of the Chapter 11 estate.
As previously disclosed, the Utility filed a complaint for injunctive and declaratory relief in the Bankruptcy Court asking the court to prohibit the ISO from charging the Utility for the 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 which would have waived certain credit standards relating to third party transactions and ordered that the ISO could only engage in power purchases on behalf of creditworthy entities. The Utility has not met the creditworthiness standards of 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.
On June 18, 2001 the Bankruptcy Court granted a motion by Reliant Energy, Inc. and Reliant Energy Services, Inc. (collectively, Reliant) to intervene in the Utility's action against the ISO. Reliant has intervened in the action to seek a permanent injunction barring the ISO from procuring power to meet the Utility's net short position in violation of its tariff and applicable FERC orders. If the Bankruptcy Court declines to issue such an injunction, Reliant has asked the Bankruptcy Court in the alternative to declare that the Utility is liable to Reliant for power procured by the ISO from Reliant and delivered to the Utility's service area.
On June 26, 2001, the Bankruptcy Court issued a preliminary injunction in the Utility's action against the ISO, prohibiting the ISO from violating the FERC orders discussed above and from filing administrative claims against the Utility in the bankruptcy for ISO charges for wholesale power purchases and other services in the ISO market. In issuing the injunction, the Bankruptcy Court noted that the FERC orders permit the ISO to schedule transactions that involve either a creditworthy buyer or a creditworthy counterparty, and noted the existence of unresolved issues regarding how to ensure these creditworthiness requirements for real-time transactions and emergency dispatch orders issued by the ISO to power sellers. The Utility believes that its only responsibility for third party power delivered to its customers and related costs since it ceased to be creditworthy is to pay the DWR the amount collected from customers pursuant to AB 1X.
In addition to alleging violations of the FERC orders and the creditworthiness provisions of the ISO tariff, the Utility's complaint 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 and violates other provisions of the Bankruptcy Code. In addition, the complaint seeks a permanent injunction prohibiting the ISO from taking such actions.
On July 20, 2001, the Bankruptcy Court granted the Utility's unopposed motion to extend the period during which the Utility has the exclusive right to file with the Bankruptcy Court a plan of reorganization that specifies, among other things, the treatment of claims. Although the initial 120-day period was to expire on August 6, 2001, the court extended the exclusivity period until December 6, 2001. If the Utility files a plan of reorganization before December 6, 2001, the exclusivity period will be extended automatically until February 4, 2002, giving the Bankruptcy Court time to consider confirmation of the Utility's plan. After the exclusivity period, and assuming the Bankruptcy Court has not yet confirmed the Utility's plan of reorganization, creditors and other parties in interest may file their own plan of reorganization.
Further, during July 2001, the Utility reached agreements with 131 of the Utility's QF suppliers, representing about 1,600 MW of the average annual 2,400 MW that the Utility receives from its QFs. Under the agreements, the Utility will assume the existing QF contracts, as modified to require the Utility to pay the QFs a fixed average energy price of 5.37 cents per kWh for five years. Currently, the contracts require the Utility to pay the QFs a price that fluctuates with natural gas prices. In addition, the Utility has agreed to pay the pre-petition debt on these 131 contracts, approximately $740 million, on the effective date of the plan of reorganization. The total amount of debt the Utility owed to QFs when it filed bankruptcy was approximately $1 billion. For certain QFs, if the effective date has not occurred by July 15, 2003, the Utility has agreed to pay 2% of the principal amount of the pre-petition debt per month until the effective date of the plan of reorganization or until July 15, 2005, when the Utility would pay the remaining pre-petition debt. The agreements require the approval of the Bankruptcy Court before they can become effective. Most of the agreements have already been approved and the Utility has filed or will file motions asking the Bankruptcy Court to approve the remaining agreements. The proposed agreements contain modifications approved by the CPUC in a decision issued on June 13, 2001, whereby certain QFs under Standard Offer contracts with the Utility who establish hardship may request that their contracts be modified to replace the energy pricing term with a one- year energy price that establishes the Utility's full short-run avoided operating costs as the lesser of (a) the energy price determined under the short-run avoided energy price formula previously adopted by the CPUC for the Utility, as in effect on March 1, 2001, or (b) the energy price determined under the short-run avoided energy price formula previously adopted by the CPUC for the Utility, as in effect on March 1, 2001, but with the QFs' actual California border gas costs substituted for the Malin and Topock gas index prices otherwise used in such formula.
Federal Securities Lawsuit
By order entered on or about May 31, 2001, the action 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, described in the Quarterly Report on Form 10-Q filed by PG&E Corporation and Pacific Gas and Electric Company for the quarter ended March 31, 2001, was transferred from the U.S. District Court for the Central District of California to the U.S. District Court for the Northern District of California.
For a discussion of other pending legal proceedings, see 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, and the Quarterly Report on Form 10-Q filed by PG&E Corporation and Pacific Gas and Electric Company for the quarter ended March 31, 2001,
Item 3. Defaults Upon Senior Securities
The Utility has authorized 75 million shares of First Preferred Stock ($25 par value) and 10 million shares of $100 First Preferred Stock ($100 par value), which may be issued as redeemable or non-redeemable preferred stock. (The Utility has not issued any $100 First Preferred Stock.) At June 30, 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 plus accumulated and unpaid dividends through the redemption date. These series of preferred stock are subject to mandatory redemption provisions entitling them to sinking funds providing for the retirement of stock outstanding. At December 31, 2000, the redemption requirements for the Utility's redeemable preferred stock with mandatory redemption provisions are $4 million per year beginning 2002, and $3 million per year beginning 2004, for the series 6.57 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), April 30, 2001 (normally payable May 15, 2001), and July 31, 2001 (normally payable August 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. Accumulated and unpaid dividends for the three-month periods ending January 31 and April 30, 2001, amounted to $12.7 million. 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.
The Utility's total defaulted commercial paper outstanding as of June 30, 2001, was $873 million. As of June 30, 2001, the Utility had drawn and had outstanding $938 million under the bank credit facility, which was also in default. For the quarter ending June 30, 2001, the Utility has not made any payments on its bank loan drawdowns or defaulted commercial paper.
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, the Utility's filing of a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code and non-payment of interest. 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 June 30, 2001, the total principal of the bonds (and related loans)
accelerated and redeemed was $454 million. As of June 30, 2001, the Utility did not make interest payments of $5.2 million on pollution control bonds series 96C, E, F and 97B. As of June 30, 2001, the Utility did not make an interest payment of $2.7 million on pollution control bond series 96A backed by bond insurance. 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, as of June 30, 2001, the Utility has not made interest payments on its 7.375% senior notes and its $1.24 billion floating rate notes. As of June 30, 2001, the total arrearage of these interest payments was $48.3 million. Also as of June 30, 2001, the Utility did not make interest payments on other long-term debt of $.5 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 4. Submission of Matters to a Vote of Security Holders
PG&E Corporation:
On May 16, 2001, 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 258,499,976 17,939,124
David A. Coulter 261,767,229 14,671,871
C. Lee Cox 261,954,208 14,484,892
William S. Davila 261,901,022 14,538,078
Robert D. Glynn, Jr. 261,618,101 14,820,999
David M. Lawrence, MD 261,873,600 14,565,500
Mary S. Metz 261,742,063 14,697,037
Carl E. Reichardt 261,752,099 14,687,001
Barry Lawson Williams 261,728,932 14,710,168
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2. Ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2001 (included as Item 2 in proxy statement):
For: 266,161,911 Against: 7,186,368 Abstain: 3,090,821 |
The proposal was approved by a majority of the shares represented and voting (including abstentions) which shares voting affirmatively also constituted a majority of the required quorum.
3. Management proposal regarding increase in shares available to be issued under the PG&E Corporation Long Term Incentive Program (included as Item 3 in proxy statement).
For: 227,672,764 Against: 44,286,370 Abstain: 4,479,966 Broker non-vote: 0 |
The proposal was approved by a majority of the shares represented and voting (including abstentions) which shares voting affirmatively also constituted a majority of the required quorum.
4. Consideration of a shareholder proposal regarding confidential shareholder voting (included as Item 4 in proxy statement):
For: 57,869,881 Against: 165,503,947 Abstain: 6,072,815 Broker non-vote: (1) 46,992,457 |
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 the proposal.
5. Consideration of a shareholder proposal regarding the treatment of abstentions (included as Item 5 in proxy statement):
For: 36,456,683 Against: 186,712,779 Abstain: 6,277,181 Broker non-vote: (1) 46,992,457 |
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 the proposal.
6. Consideration of a shareholder proposal regarding cumulative voting (included as Item 6 in proxy statement):
For: 32,248,291 Against: 190,607,501 Abstain: 6,590,851 Broker non-vote: (1) 46,992,457 |
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 the proposal.
7. Consideration of a shareholder proposal regarding the minimum number of directors (included as Item 7 in proxy statement):
For: 18,633,524 Against: 204,574,825 Abstain: 6,238,294 Broker non-vote: (1) 46,992,457 |
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 the proposal.
8. Consideration of a shareholder proposal regarding the fair price provision (Article Eighth of the Articles of Incorporation) (included as Item 8 in proxy statement):
For: 127,746,676 Against: 95,311,869 Abstain: 6,238,294 Broker non-vote: (1) 46,992,457 |
This shareholder proposal was approved as the number of shares voting affirmatively on the proposal constituted more than a majority of the shares represented and voting (including abstentions but excluding broker non- votes) with respect to the proposal, and the affirmative votes constituted a majority of the required quorum.
9. Consideration of a shareholder floor proposal introduced at the annual meeting regarding company statements in opposition to shareholder proposals was duly and properly conducted by ballot.
For: 26,744 Against: 276,403,728 Abstain: 874 Broker non-vote: (1) 0 |
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) with respect to the proposal.
10. Consideration of a shareholder floor proposal introduced at the annual meeting regarding company recommendations for voting on shareholder proposals was duly and properly conducted by ballot.
For: 27,472
Against: 276,403,492
Abstain: 774
Broker non-vote: (1) 0
--------------------
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(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.
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) with respect to the proposal.
11. Consideration of a shareholder floor proposal introduced at the annual meeting regarding information on directors' business relationships with PG&E Corporation was duly and properly conducted by ballot.
For: 29,824 Against: 276,401,140 Abstain: 774 Broker non-vote: (1) 0 |
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) with respect to the proposal.
12. Consideration of a shareholder floor proposal introduced at the annual meeting regarding information on executive and director compensation was duly and properly conducted by ballot.
For: 29,804 Against: 276,401,160 Abstain: 774 Broker non-vote: (1) 0 |
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) with respect to the proposal.
13. Consideration of a shareholder floor proposal introduced at the annual meeting regarding information on 2001 executive compensation was duly and properly conducted by ballot.
For: 29,032 Against: 276,401,760 Abstain: 506 Broker non-vote: (1) 0 |
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) with respect to the proposal.
Pacific Gas and Electric Company:
On May 16, 2001, Pacific Gas and Electric Company held its annual meeting of shareholders. Shares of capital stock of Pacific Gas and Electric Company consist of shares of common stock and shares of first preferred stock. As PG&E Corporation and a subsidiary own all of the outstanding shares of common stock, they hold approximately 95% of the combined voting power of the outstanding
capital stock of Pacific Gas and Electric Company. PG&E Corporation and the subsidiary voted all of their respective shares of common stock for the nominees named in the 2001 joint proxy statement and for the ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2001. The balance of the votes shown below were cast by holders of shares of first preferred stock. At the annual meeting, the shareholders voted as indicated below on the following matters:
1. Election of the following directors to serve until the next annual meeting of shareholders or until their successors are elected and qualified:
For Withheld
----------- ---------
David R. Andrews 338,304,620 637,790
David A. Coulter 338,321,293 621,117
C. Lee Cox 338,324,918 617,492
William S. Davila 338,331,671 610,739
Robert D. Glynn, Jr. 337,063,120 1,879,290
David M. Lawrence, MD 338,330,527 611,883
Mary S. Metz 338,327,998 614,412
Carl E. Reichardt 338,328,014 614,396
Gordon R. Smith 337,063,937 1,878,473
Barry Lawson Williams 338,324,783 617,627
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2. Ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2001:
For: 338,679,391 Against: 111,360 Abstain: 151,659 |
Item 5. Other Information
Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
Pacific Gas and Electric Company's earnings to fixed charges ratio for the six months ended June 30, 2001, was a negative 0.06. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the six months ended June 30, 2001, was a negative 0.05. The negative ratios of earnings to fixed charges and earnings to combined fixed charges and preferred stock dividends indicates a deficiency in earnings of $492 million and $510 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, relating to Pacific Gas and Electric Company's various classes of debt and first preferred stock outstanding.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
Exhibit 10 PG&E Corporation Long-Term Incentive Program, as
amended effective May 16, 3001
78
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Exhibit 11 Computation of Earnings Per Common Shares
Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges for
Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific Gas
and Electric Company
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(b) The following Current Reports on Form 8-K were filed during the first quarter of 2001 and through the date hereof (2):
1. April 6, 2001 (as amended) filed by PG&E Corporation only
Item 5. Other Events - Pacific Gas and Electric Company Bankruptcy
2. April 6, 2001 (as amended) filed by Pacific Gas and Electric Company only Item 3. Other Events - Bankruptcy or Receivership.
3. May 2, 2001 Item 9. Regulation FD Disclosure
4. May 7, 2001 - filed by PG&E Corporation only Item 9. Regulation FD Disclosure
5. May 8, 2001
Item 5. Other Events
A. Federal Lawsuit
B. Pacific Gas and Electric Company Bankruptcy
6. June 6, 2001 Item 5. Other Events Pacific Gas and Electric Company Bankruptcy Item 9. Regulation FD Disclosure
7. July 9, 2001 Item 5. Other Events
8. July 30, 2001 Item 5. Other Events
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.
PG&E CORPORATION
CHRISTOPHER P. JOHNS
Vice President and Controller
(duly authorized officer and principal
accounting officer)
PACIFIC GAS AND ELECTRIC COMPANY
DINYAR B. MISTRY
Vice President and Controller
(duly authorized officer and principal
accounting officer)
Dated: August 1, 2001
Exhibit Index
Exhibit No. Description of Exhibit
------------- --------------------------------------------------------
Exhibit 10 PG&E Corporation Long-Term Incentive Program, as amended
effective May 16, 3001
Exhibit 11 Computation of Earnings Per Common Shares
Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges for
Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific Gas and
Electric Company
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Exhibit 10
PG&E CORPORATION
LONG-TERM INCENTIVE PROGRAM
(As amended effective as of May 16, 2001)
1. Purpose of the Program
This is the controlling and definitive statement of the PG&E Corporation Long- Term Incentive Program, as amended and restated herein (hereinafter called the PROGRAM). The purpose of the PROGRAM is to advance the interests of the CORPORATION by providing ELIGIBLE PARTICIPANTS with financial incentives to promote the success of its long-term (five to ten years) business objectives, and to increase their proprietary interest in the success of the CORPORATION. It is the intent of the CORPORATION to reward those ELIGIBLE PARTICIPANTS who have a significant impact on improved long-term corporate achievements. Inasmuch as the PROGRAM is designed to encourage financial performance and to improve the value of shareholders' investment in PG&E CORPORATION, the costs of the PROGRAM will be funded from corporate earnings.
2. Program Administration
The PROGRAM shall be administered by the COMMITTEE, except that the BOARD OF DIRECTORS shall administer the PROGRAM with respect to grants of INCENTIVE AWARDS TO NON-EMPLOYEE DIRECTORS. The BOARD OF DIRECTORS may at any time revest authority to administer the PROGRAM in all respects in the BOARD OF DIRECTORS. Subject to the provisions of the PROGRAM, the COMMITTEE or the BOARD OF DIRECTORS, as the case may be, shall have full and final authority, in its sole discretion:
(a) to determine the ELIGIBLE PARTICIPANTS to whom INCENTIVE AWARDS shall be granted and the number of shares of COMMON STOCK to be awarded under each INCENTIVE AWARD, based on the recommendation of the CHIEF EXECUTIVE OFFICER (except that awards to the CHIEF EXECUTIVE OFFICER shall be based on the recommendation of the BOARD OF DIRECTORS and awards to NON-EMPLOYEE DIRECTORS shall be based on the recommendation of the COMMITTEE);
(b) to determine the time or times at which INCENTIVE AWARDS shall be granted;
(c) to designate the types of INCENTIVE AWARD being granted;
(d) to vary the OPTION vesting schedule described in the STOCK OPTION PLAN;
(e) to determine the terms and conditions, not inconsistent with the terms of the PROGRAM, of any INCENTIVE AWARD granted hereunder (including, but not limited to, the consideration and method of payment for shares purchased upon the exercise of an INCENTIVE AWARD, and any vesting acceleration or exercisability provisions in the event of a CHANGE IN CONTROL or TERMINATION), based in each case on such factors as the COMMITTEE or BOARD OF DIRECTORS shall deem appropriate;
(f) to approve forms of agreement for use under the PROGRAM;
(g) to construe and interpret the PROGRAM and any related INCENTIVE AWARD agreement and to define the terms employed herein and therein;
(h) except as provided in Section 18 hereof, to modify or amend any INCENTIVE AWARD or to waive any restrictions or conditions applicable to any INCENTIVE AWARD or the exercise or realization thereof;
(i) except as provided in Section 18 hereof, to prescribe, amend and rescind rules, regulations and policies relating to the administration of the PROGRAM;
(j) except as provided in Section 18 hereof, to suspend, terminate, modify or amend the PROGRAM;
(k) to delegate to one or more agents such administrative duties as the COMMITTEE or BOARD OF DIRECTORS may deem advisable, to the extent permitted by applicable law; and
(l) to make all other determinations and take such other action with respect to the PROGRAM and any INCENTIVE AWARD granted hereunder as the COMMITTEE may deem advisable, to the extent permitted by applicable law.
Notwithstanding the provisions contained in the foregoing paragraph, the CHIEF EXECUTIVE OFFICER shall have the authority, in his sole discretion: (a) to grant INCENTIVE AWARDS to any ELIGIBLE PARTICIPANT who, at the time of the INCENTIVE AWARD grant, (i) is not an officer of the CORPORATION or a DIRECTOR, and (ii) if such ELIGIBLE PARTICIPANT is an EMPLOYEE, is receiving an annual salary which is below the level which requires approval by the COMMITTEE; (b) to determine the time or times at which INCENTIVE AWARDS shall be granted to such ELIGIBLE PARTICIPANTS; (c) to designate the types of INCENTIVE AWARD being granted to such ELIGIBLE PARTICIPANTS; and (d) to vary the OPTION vesting schedule described in the STOCK OPTION PLAN for the OPTIONS granted to such ELIGIBLE PARTICIPANTS; provided, however, that all grants of INCENTIVE AWARDS by the CHIEF EXECUTIVE OFFICER shall conform to the guidelines previously approved by the COMMITTEE.
3. Shares of Stock Subject to the Program
There shall be reserved for use under the PROGRAM (subject to the provisions of
Section 13 hereof) a total of 49,389,230 shares of COMMON STOCK, which shares
may be authorized but unissued shares of COMMON STOCK or issued shares of COMMON
STOCK which shall have been reacquired by PG&E CORPORATION. Such shares consist
of (i) 13,000,000 shares of COMMON STOCK originally reserved for use under the
PROGRAM at the time it first became effective on January 1, 1992, (ii) 389,230
shares of COMMON STOCK remaining under the 1986 OPTION PLAN and carried over to
the PROGRAM, (iii) 10,000,000 shares of COMMON STOCK added to the PROGRAM
effective as of January 1, 1996, (iv) 11,000,000 shares of COMMON STOCK added to
the PROGRAM effective as of April 21, 1999, and (v) 15,000,000 shares of COMMON
STOCK added to the PROGRAM effective as of May 16, 2001. No more than 2,000,000
of the shares described in (i) -- (iv), and no more than 3,000,000 of the shares
described in (v) may be designated as RESTRICTED STOCK.
If (i) any INCENTIVE AWARD expires or terminates for any reason without having been exercised or purchased in full, (ii) an INCENTIVE AWARD is surrendered in exchange for one or more other INCENTIVE AWARDS, or (iii) any RESTRICTED STOCK is forfeited, then, in each such case, any unexercised, unpurchased, surrendered or forfeited shares which were subject to such INCENTIVE AWARD (except shares as to which a related TANDEM SAR has been exercised) shall again be available for the future grant of INCENTIVE AWARDS under the PROGRAM (unless the PROGRAM has terminated). In addition, shares may be reused or added back to the PROGRAM to the extent permitted by applicable law.
4. Eligibility
INCENTIVE AWARDS will be granted only to ELIGIBLE PARTICIPANTS. ISOS will be granted only to EMPLOYEES. The COMMITTEE, in its sole discretion, may grant INCENTIVE AWARDS to an ELIGIBLE PARTICIPANT who is a resident or citizen of a foreign country, with such modifications as the COMMITTEE may deem advisable to reflect the laws, tax policy or customs of such foreign country.
The PROGRAM shall not confer upon any RECIPIENT any right to continuation of employment, service as a DIRECTOR or consulting relationship with the CORPORATION; nor shall it interfere in any way with the right of the RECIPIENT or the CORPORATION to terminate such employment, service as a DIRECTOR or consulting relationship at any time, with or without cause.
5. Designation of Incentive Awards
At the time of the grant of each INCENTIVE AWARD under the Program, the COMMITTEE (or the CHIEF EXECUTIVE OFFICER, in the case of INCENTIVE AWARDS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof, or the BOARD OF DIRECTORS, in the case of INCENTIVE AWARDS granted by the BOARD OF DIRECTORS to NON-EMPLOYEE DIRECTORS) shall determine whether such INCENTIVE AWARD is to be designated as an ISO, NON-QUALIFIED STOCK OPTION, SAR, DIVIDEND EQUIVALENT,
PERFORMANCE UNIT, stock grant, RESTRICTED STOCK, LSAR, PHANTOM STOCK or other STOCK-BASED AWARD; provided, however, that ISOS may be granted only to EMPLOYEES.
Notwithstanding such designation, to the extent that the aggregate FAIR MARKET VALUE (determined for each share as of the date of grant of the OPTION covering each share) of the shares with respect to which OPTIONS designated as ISOS become exercisable for the first time by any RECIPIENT during any calendar year exceeds $100,000, such OPTIONS shall be treated as NON-QUALIFIED STOCK OPTIONS.
Any INCENTIVE AWARD may be granted alone, contingent upon, in addition to or in TANDEM with one or more other INCENTIVE AWARDS granted under the PROGRAM. In addition, except as provided in Section 12 hereof, any INCENTIVE AWARD may be granted in exchange for one or more other INCENTIVE AWARDS.
6. Stock Options, Tandem Stock Appreciation Rights and Tandem Dividend Equivalents
Except as provided in Section 9 below (relating to grants of INCENTIVE AWARDS to NON-EMPLOYEE DIRECTORS), the COMMITTEE, in its sole discretion, may grant ISOS, NON-QUALIFIED STOCK OPTIONS, TANDEM SARS and TANDEM DIVIDEND EQUIVALENTS to ELIGIBLE PARTICIPANTS, subject to the terms and conditions set forth in the STOCK OPTION PLAN attached hereto as Exhibit A.
7. Performance Units
Except as provided in Section 9 below (relating to grants of INCENTIVE AWARDS to NON-EMPLOYEE DIRECTORS), the COMMITTEE, in its sole discretion, may grant PERFORMANCE UNITS to ELIGIBLE PARTICIPANTS, subject to the terms and conditions set forth in the PERFORMANCE UNIT PLAN attached hereto as Exhibit B.
8. Other Incentive Awards
Except as provided in Section 9 below (relating to grants of INCENTIVE AWARDS to NON-EMPLOYEE DIRECTORS), the COMMITTEE, in its sole discretion, may grant other INCENTIVE AWARDS (including, but not limited to, SARS granted without OPTIONS, DIVIDEND EQUIVALENTS granted without OPTIONS, stock grants, RESTRICTED STOCK, LSARS, PHANTOM STOCK or other STOCK-BASED AWARDS) to ELIGIBLE PARTICIPANTS, subject to such terms and conditions as the COMMITTEE shall deem appropriate.
9. Grants of Incentive Awards to Non-Employee Directors
NON-EMPLOYEE DIRECTORS will only be eligible to be granted DIRECTOR RESTRICTED STOCK, PHANTOM STOCK and NON-QUALIFIED STOCK OPTIONS in accordance with, and subject to the terms and conditions contained in, the NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN RULES attached hereto as Exhibit C.
10. Termination of Employment or Relationship with the CORPORATION
The COMMITTEE may, in its sole discretion, establish terms and conditions pertaining to the effect of TERMINATION on INCENTIVE AWARDS granted to a RECIPIENT prior to TERMINATION, to the extent permitted by applicable law.
11. Tax Withholding
When a RECIPIENT incurs tax liability in connection with the exercise of an INCENTIVE AWARD or the receipt of shares of COMMON STOCK pursuant to an INCENTIVE AWARD, which tax liability is subject to tax withholding under applicable tax laws, and the RECIPIENT is obligated to pay the CORPORATION an amount required to be withheld under applicable tax laws, the RECIPIENT may satisfy the withholding tax obligation by (i) electing to have the CORPORATION withhold such amount from his or her current compensation through payroll deductions, or (ii) making a direct payment to the CORPORATION in cash or by check.
The COMMITTEE may, in its sole discretion, permit a RECIPIENT to satisfy all or part of his or her withholding tax obligations by having the CORPORATION withhold from the shares to be issued to the RECIPIENT that number of shares
having a FAIR MARKET VALUE equal to the amount required to be withheld determined on the date when taxes otherwise would be withheld in cash. The payment of withholding taxes in this manner, if permitted by the COMMITTEE, shall be subject to such restrictions as the COMMITTEE may impose, including any restrictions required by rules of the Securities and Exchange Commission.
12. Replacement of Grants
The COMMITTEE may, in its sole discretion, offer a RECIPIENT (other than NON- EMPLOYEE DIRECTORS) the option of surrendering an unexercised OPTION or other INCENTIVE AWARD in exchange for another INCENTIVE AWARD of the same type or for a different type of INCENTIVE AWARD; provided, however, that no OPTION or INCENTIVE AWARD may be exchanged for a new OPTION or INCENTIVE AWARD having an OPTION PRICE or purchase price that is lower than the OPTION PRICE or purchase price of the original OPTION or INCENTIVE AWARD.
13. Deferral of Payments
The COMMITTEE may, in its sole discretion, approve a RECIPIENT'S deferral of any cash payments which may become due under the PROGRAM. Such deferrals shall be subject to any conditions, restrictions or requirements as the COMMITTEE may determine.
14. Adjustments Upon Changes in Number or Value of Shares of Common Stock
If there are any changes in the number or value of shares of COMMON STOCK by reason of stock dividends, stock splits, reverse stock splits, recapitalizations, mergers, consolidations or other events that materially increase or decrease the number or value of issued and outstanding shares of COMMON STOCK, the COMMITTEE may make such adjustments as it shall deem appropriate, in order to prevent dilution or enlargement of rights.
15. Non-Transferability of Incentive Awards
An INCENTIVE AWARD shall not be transferable by the RECIPIENT otherwise than by will or the laws of descent and distribution, or pursuant to a qualified domestic relations order as defined by the CODE, Title I of ERISA or the rules thereunder. During the lifetime of the RECIPIENT, an INCENTIVE AWARD may be exercised only by the RECIPIENT or by an alternate payee under a qualified domestic relations order.
16. Change in Control
Upon the occurrence of a CHANGE IN CONTROL (as defined below):
(a) Any time periods relating to the exercise or realization of any INCENTIVE AWARD granted hereunder shall be accelerated so that such INCENTIVE AWARD may be immediately exercised or realized in full;
(b) All shares of RESTRICTED STOCK granted hereunder shall immediately cease to be forfeitable; and
(c) All conditions relating to the realization of any STOCK-BASED AWARD granted hereunder shall immediately terminate.
A "CHANGE IN CONTROL" shall be deemed to have occurred if:
(a) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or any trustee, agent or other fiduciary for any such plan acting in such person's capacity as such fiduciary), directly or indirectly, becomes the beneficial owner of securities of the CORPORATION representing twenty percent (20%) or more of the combined voting power of the CORPORATION's then outstanding securities;
(b) during any two consecutive years, individuals who at the beginning of such a period constitute the BOARD OF DIRECTORS cease for any reason to constitute at least a majority of the BOARD OF DIRECTORS, unless the election, or the nomination for election by the shareholders of the CORPORATION, of each new DIRECTOR was approved by a
vote of at least two-thirds (2/3) of the DIRECTORS then still in office who were DIRECTORS at the beginning of the period; or
(c) the shareholders of the CORPORATION shall have approved (i) any consolidation or merger of the CORPORATION other than a merger or consolidation which would result in the voting securities of the CORPORATION outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70 percent of the Combined Voting Power of the CORPORATION, such surviving entity or the parent of such surviving entity outstanding immediately after the merger or consolidation; (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the CORPORATION, or (iii) any plan or proposal for the liquidation or dissolution of the CORPORATION. For purposes of this paragraph, the term Combined Voting Power shall mean the combined voting power of the CORPORATION's or other relevant entity's then outstanding voting securities.
17. Listing and Registration of Shares
Each INCENTIVE AWARD shall be subject to the requirement that if at any time the COMMITTEE shall determine, in its discretion, that the listing, registration or qualification of the shares covered thereby under any securities exchange or under any state or federal law or the consent or approval of any governmental regulatory body, including the California Public Utilities Commission, is necessary or desirable as a condition of, or in connection with, the granting of such INCENTIVE AWARD or the issue or purchase of shares thereunder, such INCENTIVE AWARD may not be exercised in whole or in part unless and until such listing, registration, qualification, consent or approval shall have been effected or obtained free of any conditions not acceptable to the COMMITTEE.
18. Amendment and Termination of the Program and Incentive Awards
The BOARD OF DIRECTORS or the COMMITTEE may at any time suspend, terminate, modify or amend the PROGRAM in any respect; provided, however, that to the extent necessary and desirable to comply with Section 422 of the CODE (or any other applicable law or regulation, including the requirements of any stock exchange on which the COMMON STOCK is listed or quoted), shareholder approval of any PROGRAM amendment shall be obtained in such a manner and to such a degree as is required by the applicable law or regulation.
No suspension, termination, modification or amendment of the PROGRAM may, without the consent of the RECIPIENT, adversely affect his or her rights under INCENTIVE AWARDS theretofore granted to such RECIPIENT. In the event of amendments to the CODE or applicable rules or regulations relating to ISOS subsequent to the date hereof, the CORPORATION may amend the PROGRAM, and the CORPORATION and RECIPIENTS holding OPTION agreements may agree to amend outstanding OPTION agreements, to conform to such amendments.
The BOARD OF DIRECTORS or COMMITTEE may make such amendments or modifications in the terms and conditions of any INCENTIVE AWARD as it may deem advisable, or cancel or annul any grant of an INCENTIVE AWARD; provided, however, that no such amendment, modification, cancellation or annulment may, without the consent of the RECIPIENT, adversely affect his or her rights under such INCENTIVE AWARD; and provided further the BOARD OF DIRECTORS or COMMITTEE may not reduce the OPTION PRICE or purchase price of any OPTION or INCENTIVE AWARD below the original OPTION PRICE or purchase price.
Notwithstanding the foregoing, the BOARD OF DIRECTORS or COMMITTEE reserves the
right, in its sole discretion, to (i) convert any outstanding ISOS to NON-
QUALIFIED STOCK OPTIONS, (ii) to require a RECIPIENT to forfeit any unexercised
or unpurchased INCENTIVE AWARDS, any shares received or purchased pursuant to an
INCENTIVE AWARD, or any gains realized by virtue of the receipt of an INCENTIVE
AWARD in the event that such RECIPIENT competes against the CORPORATION, and
(iii) to cancel or annul any grant of an INCENTIVE AWARD in the event of a
RECIPIENT'S TERMINATION FOR CAUSE. For purposes of the PROGRAM, "TERMINATION FOR
CAUSE" shall include, but not be limited to, termination because of dishonesty,
criminal offense or violation of a work rule, and shall be determined by, and in
the sole discretion of, the BOARD OF DIRECTORS or COMMITTEE.
19. Effective Date of the Program and Duration
The Program first became effective as of January 1, 1992. The first amendment and restatement of the PROGRAM as of January 1, 1996, was approved by the shareholders of Pacific Gas and Electric Company at its Annual Meeting on April 17, 1996. Effective January 1, 1997, the PROGRAM was assumed by PG&E CORPORATION. At its meeting on December 17, 1997, the BOARD OF DIRECTORS amended and restated the PROGRAM effective January 1, 1998, to (i) reflect the adoption of new RULE 16B-3 which became effective November 1, 1996, and (ii) provide automatic formula awards of NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK to NON-EMPLOYEE DIRECTORS within the limits of the PROGRAM as previously approved by shareholders in 1996. The PROGRAM was subsequently amended on October 21, 1998, April 21, 1999, February 16, 2000, September 19, 2000, and February 21, 2001. Effective May 16, 2001, the PROGRAM was amended to add 15,000,000 shares of COMMON STOCK to the total number of shares of COMMON STOCK reserved for use under the PROGRAM. Unless terminated sooner pursuant to Section 16 hereof, the PROGRAM shall terminate on December 31, 2005.
20. Definitions
(a) BOARD OF DIRECTORS means the Board of Directors of PG&E CORPORATION.
(b) CHANGE IN CONTROL has the meaning set forth in Section 16 hereof.
(c) CHIEF EXECUTIVE OFFICER means the Chief Executive Officer of PG&E
CORPORATION.
(d) CODE means the Internal Revenue Code of 1986, as amended from time to time.
(e) COMMITTEE means the Nominating and Compensation Committee of the BOARD OF DIRECTORS or any successor to such committee.
(f) COMMON STOCK means common shares of PG&E CORPORATION with no par value and any class of common shares into which such common shares hereafter may be converted.
(g) CONSULTANT means any person, including an advisor, who is engaged by the CORPORATION to render services.
(h) CORPORATION means PG&E CORPORATION, and any parent corporation (as defined in Section 424(e) of the CODE) or subsidiary corporation (as defined in Section 424(f) of the CODE).
(i) DIRECTOR means any person who is a member of the BOARD OF DIRECTORS or the Board of Directors of any parent corporation (as defined in Section 424(e) of the CODE) which may hereafter be established, including an advisory, emeritus or honorary director.
(j) DIRECTOR RESTRICTED STOCK means RESTRICTED STOCK granted to a NON-EMPLOYEE DIRECTOR under the NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN.
(k) DIVIDEND EQUIVALENT means a right that entitles the RECIPIENT to receive cash or COMMON STOCK based on the dividends declared on the COMMON STOCK covered by such right.
(l) ELIGIBLE PARTICIPANT means any KEY EMPLOYEE. It also means, if so identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the case of INCENTIVE AWARDS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), other EMPLOYEES, DIRECTORS, CONSULTANTS, employees or consultants of any affiliates of PG&E CORPORATION, and other persons whose participation in the PROGRAM is deemed by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the case of INCENTIVE AWARDS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof) to be in the best interests of the CORPORATION.
(m) EMPLOYEE means any person who is employed by the CORPORATION. The payment of a director's fee or consulting fee by the CORPORATION shall not be sufficient to constitute "employment" by the CORPORATION.
(n) ERISA means the Employee Retirement Income Security Act of 1974, as amended.
(o) EXCHANGE ACT means the Securities Exchange Act of 1934, as amended.
(p) FAIR MARKET VALUE means the closing price of the COMMON STOCK reported on the New York Stock Exchange Composite Transactions for the date specified for determining such value.
(q) INCENTIVE AWARD means any ISO, NON-QUALIFIED STOCK OPTION, SAR, DIVIDEND EQUIVALENT, PERFORMANCE UNIT or other STOCK-BASED AWARD granted under the PROGRAM.
(r) ISO means an OPTION intended to qualify as an incentive stock option under
Section 422 of the CODE.
(s) KEY EMPLOYEE means the Corporate Secretary, Treasurer, Vice Presidents and other executive officers of PG&E CORPORATION above the rank of Vice President. It also means, if so identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the case of INCENTIVE AWARDS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), executive officers of wholly-owned subsidiaries of PG&E CORPORATION (including subsidiaries which become such after adoption of the PROGRAM) and any other key management employee of PG&E CORPORATION or any wholly-owned subsidiary of PG&E CORPORATION.
(t) LSAR means a limited stock appreciation right which is exercisable only in the event of a CHANGE IN CONTROL.
(u) 1986 OPTION PLAN means the Pacific Gas and Electric Company 1986 Stock Option Plan, as amended to date.
(v) NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE.
(w) NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN RULES means the Non-Employee Director Stock Incentive Plan attached hereto as Exhibit C or any successor rules which the BOARD OF DIRECTORS may adopt from time to time with respect to the grant of INCENTIVE AWARDS to NON-EMPLOYEE DIRECTORS under the PROGRAM.
(x) NON-QUALIFIED STOCK OPTION means any OPTION which is not an ISO.
(y) OPTION means an option to purchase shares of COMMON STOCK granted under the STOCK OPTION PLAN.
(z) OPTION PRICE means the purchase price for the COMMON STOCK upon exercise of an OPTION.
(aa) PERFORMANCE UNIT means a performance unit granted under the PERFORMANCE UNIT PLAN.
(bb) PERFORMANCE UNIT PLAN means the Performance Unit Plan Rules attached hereto as Exhibit B or any successor rules which the COMMITTEE may adopt from time to time with respect to the grant of PERFORMANCE UNITS under the PROGRAM.
(cc) PG&E CORPORATION means PG&E CORPORATION, a California corporation.
(dd) PHANTOM STOCK means allocated hypothetical shares of COMMON STOCK that can be converted at a future date into cash or stock.
(ee) PROGRAM means the PG&E Corporation Long-Term Incentive Program set forth herein and as may be amended from time to time.
(ff) RECIPIENT means the ELIGIBLE PARTICIPANT receiving the INCENTIVE AWARD, or his or her legal representative, legatees, distributees or alternate payees, as the case may be.
(gg) RESTRICTED STOCK means COMMON STOCK that is subject to forfeiture by the RECIPIENT to the CORPORATION under such circumstances as may be specified by the COMMITTEE in its sole discretion.
(hh) RETIREMENT means termination of employment with the CORPORATION at age 55 or later, provided that the ELIGIBLE PARTICIPANT was employed by the CORPORATION for at least five consecutive years prior to the date of termination.
(ii) RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor to Rule 16b-3, as in effect when discretion is being exercised with respect to the Plan.
(jj) SAR means a stock appreciation right whose value is based on the increase in the FAIR MARKET VALUE of the COMMON STOCK covered by such right.
(kk) SECTION 16 OFFICER means any person who is designated by the BOARD OF DIRECTORS as an executive officer of PG&E CORPORATION and any other person who is designated as an officer of PG&E CORPORATION for purposes of Section 16 of the EXCHANGE ACT.
(ll) STOCK-BASED AWARD means any award that is valued in whole or in part by reference to, or is otherwise based on, the COMMON STOCK, including, but not limited to, stock grants, RESTRICTED STOCK, LSARS and PHANTOM STOCK.
(mm) STOCK OPTION PLAN means the Stock Option Plan Rules attached hereto as Exhibit A or any successor rules which the COMMITTEE may adopt from time to time with respect to the grant of OPTIONS under the PROGRAM.
(nn) TANDEM refers to an INCENTIVE AWARD granted in conjunction with another INCENTIVE AWARD.
(oo) TERMINATION occurs when an EMPLOYEE ceases to be employed by the CORPORATION as a common law employee, when a DIRECTOR ceases to be a member of the BOARD OF DIRECTORS or the Board of Directors of any parent corporation which may hereafter be established (as the case may be), or when the relationship between the CORPORATION and a CONSULTANT or other ELIGIBLE PARTICIPANT terminates, as the case may be.
(pp) TERMINATION FOR CAUSE has the meaning set forth in Section 18 hereof.
EXHIBIT A
PG&E CORPORATION
STOCK OPTION PLAN
(As amended effective as of May 16, 2001)
1. Purpose of the Plan
This is the controlling and definitive statement of the PG&E Corporation Stock Option Plan set forth herein and as may be amended from time to time (hereinafter called the PLAN). The purpose of the PLAN is to advance the interests of the CORPORATION by providing ELIGIBLE PARTICIPANTS with financial incentives to promote the success of its long-term (five to ten years) business objectives, and to increase their proprietary interest in the success of the CORPORATION. It is the intent of the CORPORATION to reward those ELIGIBLE PARTICIPANTS who have a significant impact on improved long-term corporate achievements. Inasmuch as the PLAN is designed to encourage financial performance and to improve the value of shareholders' investment in PG&E CORPORATION, the costs of the PLAN will be funded from corporate earnings.
2. Plan Administration
The PLAN shall be administered by the COMMITTEE, which shall be constituted in such a manner as to comply with the rules governing a plan intended to qualify as a discretionary plan under RULE 16b-3.
Subject to the provisions of the PLAN, the COMMITTEE shall have full and final authority, in its sole discretion:
(a) to determine the ELIGIBLE PARTICIPANTS to whom OPTIONS shall be granted and the number of shares of COMMON STOCK to be awarded under each OPTION, based on the recommendation of the CHIEF EXECUTIVE OFFICER (except that awards to the CHIEF EXECUTIVE OFFICER shall be shall be based on the recommendation of the BOARD OF DIRECTORS); provided, however, that the number of shares of COMMON STOCK to be awarded under each OPTION shall be subject to the limitations specified in Section 5 hereof;
(b) to determine the time or times at which OPTIONS shall be granted;
(c) to designate the OPTIONS being granted as ISOS or NON-QUALIFIED STOCK OPTIONS;
(d) to vary the OPTION vesting schedule described in Section 11 hereof;
(e) to determine the terms and conditions, not inconsistent with the terms of the PLAN, of any OPTION granted hereunder (including, but not limited to, the consideration and method of payment for shares purchased upon the exercise of an OPTION, and any vesting acceleration or exercisability provisions in the event of a CHANGE IN CONTROL or TERMINATION), based in each case on such factors as the COMMITTEE shall deem appropriate;
(f) to approve forms of agreement for use under the PLAN;
(g) to construe and interpret the PLAN and any related OPTION agreement and to define the terms employed herein and therein;
(h) except as provided in Section 18 hereof, to modify or amend any OPTION or to waive any restrictions or conditions applicable to any OPTION or the exercise thereof;
(i) except as provided in Section 18 hereof, to prescribe, amend and rescind rules, regulations and policies relating to the administration of the PLAN;
(j) except as provided in Section 18 hereof, to suspend, terminate, modify or amend the PLAN;
(k) to delegate to one or more agents such administrative duties as the COMMITTEE may deem advisable, to the extent permitted by applicable law; and
(l) to make all other determinations and take such other action with respect to the PLAN and any OPTION granted hereunder as the COMMITTEE may deem advisable, to the extent permitted by applicable law.
Notwithstanding the provisions contained in the foregoing paragraph, the CHIEF EXECUTIVE OFFICER shall have the authority, in his sole discretion: (a) to grant OPTIONS to any ELIGIBLE PARTICIPANT who, at the time of the OPTION grant, (i) is not an officer of the CORPORATION or a DIRECTOR, and (ii) if such ELIGIBLE PARTICIPANT is an EMPLOYEE, is receiving an annual salary which is below the level which requires approval by the COMMITTEE; (b) to determine the time or times at which OPTIONS shall be granted to such ELIGIBLE PARTICIPANTS; (c) to designate the OPTIONS being granted to such ELIGIBLE PARTICIPANTS as ISOS or NON-QUALIFIED STOCK OPTIONS; and (d) to vary the OPTION vesting schedule described in Section 11 hereof for the OPTIONS granted to such ELIGIBLE PARTICIPANTS; provided, however, that (x) all grants of OPTIONS by the CHIEF EXECUTIVE OFFICER shall conform to the guidelines previously approved by the COMMITTEE, and (y) the number of shares of COMMON STOCK to be awarded under each OPTION shall be subject to the limitations specified in Section 5 hereof.
3. Shares of Stock Subject to the Plan
There shall be reserved for use under the PLAN and for the grant of any other incentive awards pursuant to the PROGRAM (subject to the provisions of Section 14 hereof) a total of 49,389,230 shares of COMMON STOCK, which shares may be authorized but unissued shares of COMMON STOCK or issued shares of COMMON STOCK which shall have been reacquired by PG&E CORPORATION.
If any OPTION expires or terminates for any reason without having been exercised in full, then any unexercised, shares which were subject to such OPTION (except shares as to which a related TANDEM SAR has been exercised) shall again be available for the future grant of OPTIONS under the PLAN (unless the PLAN has terminated). In addition, shares may be reused or added back to the PLAN to the extent permitted by applicable law.
4. Eligibility
OPTIONS will be granted only to ELIGIBLE PARTICIPANTS. ISOS will be granted only to EMPLOYEES. The COMMITTEE, in its sole discretion, may grant OPTIONS to an ELIGIBLE PARTICIPANT who is a resident or citizen of a foreign country, with such modifications as the COMMITTEE may deem advisable to reflect the laws, tax policy or customs of such foreign country.
The PLAN shall not confer upon any OPTIONEE any right to continuation of employment, service as a DIRECTOR or consulting relationship with the CORPORATION; nor shall it interfere in any way with the right of the OPTIONEE or the CORPORATION to terminate such employment, service as a DIRECTOR or consulting relationship at any time, with or without cause.
5. Limitation on Options and SARs Awarded to Any Eligible Participant
The aggregate number of shares of COMMON STOCK with respect to which any ELIGIBLE PARTICIPANT may be granted OPTIONS and SARS under the PLAN during any calendar year shall in no event exceed two percent (2%) of the total number of shares reserved for use under the PLAN.
6. Designation of Options
At the time of the grant of each OPTION under the PLAN, the COMMITTEE (or the CHIEF EXECUTIVE OFFICER, in the case of OPTIONS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof) shall determine whether such OPTION is to be designated as an ISO or a NON-QUALIFIED STOCK OPTION; provided, however, that ISOS may be granted only to EMPLOYEES.
Notwithstanding such designation, to the extent that the aggregate FAIR MARKET VALUE (determined for each share as of the date of grant of the OPTION covering each share) of the shares with respect to which OPTIONS designated as ISOS become exercisable for the first time by any OPTIONEE during any calendar year exceeds $100,000, such OPTIONS shall be treated as NON-QUALIFIED STOCK OPTIONS.
7. Option Price
The OPTION PRICE of the COMMON STOCK under each OPTION issued shall be the FAIR MARKET VALUE of the COMMON STOCK on the date of grant.
8. Stock Appreciation Rights
At the discretion of the COMMITTEE, an OPTION may be granted with or without a
TANDEM SAR which permits the OPTIONEE to surrender unexercised an OPTION or
portion thereof and to receive in exchange a payment having a value equal to the
difference between (x) the FAIR MARKET VALUE of the COMMON STOCK covered by the
surrendered portion of the OPTION on the date the SAR is exercised and (y) the
OPTION PRICE for such COMMON STOCK. The SAR is subject to the same terms and
conditions as the related OPTION, except that (i) the SAR may be exercised only
when there is a positive spread (i.e., when the FAIR MARKET VALUE of the COMMON
STOCK subject to the OPTION exceeds the OPTION PRICE), (ii) in accordance with
Section 9 hereof, payment of the DEA (if any) to the OPTIONEE may be restricted,
and (iii) if the OPTIONEE is a SECTION 16 OFFICER, DIRECTOR or other person
whose transactions in the COMMON STOCK are subject to Section 16(b) of the
EXCHANGE ACT, the SAR may be exercised only during the period beginning on the
third (3rd) business day following the date of release of the CORPORATION's
quarterly or annual statement of earnings and ending on the twelfth (12th)
business day following such date. Upon the exercise of a SAR, the number of
shares subject to exercise under the related OPTION shall be automatically
reduced by the number of shares represented by the OPTION or portion thereof
surrendered. No payment will be required from the OPTIONEE upon the exercise of
a SAR, except that any amount necessary to satisfy applicable federal, state or
local tax requirements shall be withheld.
9. Dividend Equivalent Account
At the discretion of the COMMITTEE, an OPTION may be granted with or without TANDEM DIVIDEND EQUIVALENTS. When an OPTION is granted with TANDEM DIVIDEND EQUIVALENTS, a Dividend Equivalent Account ("DEA") shall be established for the OPTIONEE. This DEA shall be credited quarterly on each dividend record date with dividends which would have been paid on the COMMON STOCK subject to the unexercised portion of the OPTION (including any portion which has not yet vested on the record date), if such portion had been exercised. Except as provided in Section 12(d) hereof, at the time the OPTION or any related SAR is exercised, the OPTIONEE shall receive all funds which have accumulated in the DEA with respect to the shares of COMMON STOCK for which the OPTION or SAR is being exercised; provided, however, that if the OPTIONEE exercises a SAR, such DEA funds shall only be paid to the OPTIONEE if (i) the percentage increase in the FAIR MARKET VALUE of the COMMON STOCK over the OPTION PRICE averages at least five percent (5%) per year for the first five (5) years after the grant, or (ii) in the case of OPTIONS held for longer than five (5) years from the date of grant, such FAIR MARKET VALUE has increased by at least twenty-five percent (25%) over the OPTION PRICE.
10. Terms of Options
The term of each ISO shall be for ten (10) years from the date of grant, subject to earlier termination as provided in Section 12 hereof. The term of each NON- QUALIFIED STOCK OPTION shall be ten (10) years and one (1) day from the date of grant, subject to earlier termination as provided in Section 12 hereof. Any provision of the PROGRAM to the contrary notwithstanding, no OPTION shall be exercised after the time limitations stated in this Section 10.
11. Limitations on Exercise
(a) Each OPTION granted under the PROGRAM shall become exercisable and vested
only to the following extent: (i) up to one-third (1/3) of the OPTIONS granted
may be exercised on or after the second (2nd) anniversary of the date of grant;
(ii) up to two-thirds (2/3) of the OPTIONS granted may be exercised on or after
the third (3rd) anniversary of the date of grant; and (iii) up to one hundred
percent (100%) of the OPTIONS granted may be exercised on or after the fourth
(4th) anniversary of the date of grant.
(b) No OPTION under the PROGRAM designated by the COMMITTEE as an ISO and granted before January 1, 1987 may be exercised while there is outstanding in the hands of the OPTIONEE any ISO which was granted before the granting of the ISO hereunder sought to be exercised. For this purpose an ISO shall be treated as outstanding until such OPTION is (i) exercised in full, (ii) surrendered in full by exercising SARS pursuant to Section 8 hereof, or (iii) rendered void by reason of lapse of time.
12. Termination of Employment or Relationship with the CORPORATION
(a) In the event of a TERMINATION by reason of a discharge or TERMINATION FOR CAUSE, any unexercised OPTIONS theretofore granted to an OPTIONEE under the PROGRAM shall forthwith terminate.
(b) In the event of a TERMINATION by reason of RETIREMENT, all OPTIONS held by the OPTIONEE, to the extent that such OPTIONS have not previously expired or been exercised, shall become fully exercisable and vested, notwithstanding the provisions of Section 11(a) hereof, and the OPTIONEE shall have the right to exercise such OPTIONS in full at any time within their respective terms or within five (5) years after such RETIREMENT, whichever is shorter. This five- year period shall be extended if an OPTIONEE remains on the BOARD OF DIRECTORS after RETIREMENT. In such case, the OPTIONS may be exercised as long as the OPTIONEE remains a DIRECTOR and for a period of six (6) months thereafter, or within five (5) years after RETIREMENT, whichever is longer; provided, however, that no OPTION may be exercised after the expiration of its term. To the extent any ISO held by the OPTIONEE is exercised after the expiration of three (3) months after such TERMINATION, the exercise will be deemed to involve the exercise of a NON-QUALIFIED STOCK OPTION.
(c) In the event of a TERMINATION by reason of disability or death, all OPTIONS held by the OPTIONEE, to the extent that such OPTIONS have not previously expired or been exercised, shall become fully exercisable and vested, notwithstanding the provisions of Section 11(a) hereof, and the OPTIONEE (or the OPTIONEE'S estate or a person who acquired the right to exercise such OPTIONS by bequest or inheritance) shall have the right to exercise such OPTIONS at any time within their respective terms or within one (1) year after the date of such TERMINATION, whichever is shorter. The term "disability" shall, for the purposes of the PLAN, be defined in Section 22(e)(3) of the CODE.
(d) In the event of a TERMINATION by reason of a divestiture or change in control of a subsidiary of PG&E CORPORATION, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Section 424(f) of the CODE or in the event of a TERMINATION coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E CORPORATION, all OPTIONS held by the OPTIONEE, to the extent that such OPTIONS have not previously expired or been exercised, shall become fully exercisable and vested, notwithstanding the provisions of Section 11(a) hereof, and the OPTIONEE shall have the right to exercise such OPTIONS in full at any time within their respective terms or within three (3) years after such TERMINATION, whichever is shorter. This three-year period shall be extended if an OPTIONEE remains on the BOARD OF DIRECTORS after such TERMINATION. In such case, the OPTIONS may be exercised as long as the OPTIONEE remains a DIRECTOR and for a period of six (6) months thereafter, or within three (3) years after such TERMINATION, whichever is longer; provided, however, that no OPTION may be exercised after the expiration of its term. To the extent any ISO held by the OPTIONEE is exercised after the expiration of three (3) months after such TERMINATION, the exercise will be deemed to involve the exercise of a NON- QUALIFIED STOCK OPTION.
(e) In the event of a TERMINATION within one year after a CHANGE IN CONTROL of
the CORPORATION (other than a TERMINATION covered by clauses (a), (b), or (c)
above), OPTIONEE shall have the right to exercise OPTIONS which OPTIONEE then
holds (which OPTIONS will have been accelerated previously in accordance with
Section 16 below), to the extent that such OPTIONS have not previously expired
or been exercised, in full at any time within their respective terms or within
three (3) years after such TERMINATION, whichever is shorter. This three-year
period shall be extended if an OPTIONEE remains on the BOARD OF DIRECTORS after
such TERMINATION. In such case, the OPTIONS may be exercised as long as the
OPTIONEE remains a DIRECTOR and for a period of six (6) months thereafter, or
within three (3) years after such TERMINATION, whichever is longer; provided,
however, that no OPTION may be exercised after the expiration of its term. To
the extent any ISO held by the OPTIONEE is exercised after the expiration of
three (3) months after such TERMINATION, the exercise will be deemed to involve
the exercise of a NON-QUALIFIED STOCK OPTION.
(f) In the event of a TERMINATION for any reason other than those specified in
subparagraphs (a) through (e) above, (i) any unexercised OPTION or OPTIONS
granted under the PROGRAM shall be deemed canceled and terminated forthwith,
except that the OPTIONEE may exercise any unexercised OPTIONS theretofore
granted which are otherwise exercisable and vested within the provisions of
Section 11(a) hereof, during the balance of their respective terms or within
thirty (30) days of such TERMINATION, whichever is shorter, and (ii) the DEA (if
any) shall not be credited with any dividends paid after the date of such
TERMINATION.
(g) Notwithstanding the provisions of subparagraphs (a) through (f) above, the COMMITTEE may, in its sole discretion, establish different terms and conditions pertaining to the effect of TERMINATION, to the extent permitted by applicable federal and state law.
13. Payment for Shares Upon Exercise of Options
The exercise of any OPTION shall be contingent upon receipt by the CORPORATION of (i) cash (including any DEA funds payable to the OPTIONEE in connection with the exercise of such OPTION), (ii) check, (iii) shares of COMMON STOCK, (iv) an executed exercise notice together with irrevocable instructions to a broker to either sell the shares subject to the OPTION or hold such shares as collateral for a margin loan and to promptly deliver to the CORPORATION the amount of sale or loan proceeds required to pay the OPTION PRICE, (v) any combination of the foregoing in an amount equal to the full OPTION PRICE of the shares being purchased, or (vi) such other consideration and method of payment, other than a note from the OPTIONEE, as the COMMITTEE, in its sole discretion, may allow (which, in the case of an ISO shall be determined at the time of grant), to the extent permitted by applicable law. For purposes of this paragraph, shares of COMMON STOCK that are delivered in payment of the OPTION PRICE must have been previously owned by the OPTIONEE for a minimum of one year, and shall be valued at their FAIR MARKET VALUE as of the date of the exercise of the OPTION. The CORPORATION shall not make loans to any OPTIONEE for the purpose of exercising OPTIONS.
14. Adjustments Upon Changes in Number or Value of Shares of Common Stock
If there are any changes in the number or value of shares of COMMON STOCK by reason of stock dividends, stock splits, reverse stock splits, recapitalizations, mergers, consolidations or other events that materially increase or decrease the number or value of issued and outstanding shares of COMMON STOCK, the COMMITTEE may make such adjustments as it shall deem appropriate, in order to prevent dilution or enlargement of rights.
15. Non-Transferability of Options
An OPTION shall not be transferable by the OPTIONEE otherwise than by will or the laws of descent and distribution, or pursuant to a qualified domestic relations order as defined by the CODE, Title I of ERISA or the rules thereunder. During the lifetime of the OPTIONEE, an OPTION may be exercised only by the OPTIONEE or by an alternate payee under a qualified domestic relations order.
16. Change in Control
Upon the occurrence of a CHANGE IN CONTROL (as defined below), any time periods relating to the exercise of any OPTION granted hereunder shall be accelerated so that such OPTION may be immediately exercised in full.
A "CHANGE IN CONTROL" shall be deemed to have occurred if:
(a) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or any trustee, agent or other fiduciary for any such plan acting in such person's capacity as such fiduciary), directly or indirectly, becomes the beneficial owner of securities of PG&E CORPORATION representing twenty percent (20%) or more of the combined voting power of the CORPORATION's then outstanding securities;
(b) during any two consecutive years, individuals who at the beginning of such a period constitute the BOARD OF DIRECTORS cease for any reason to constitute at least a majority of the BOARD OF DIRECTORS, unless the election, or the nomination for election by the shareholders of the CORPORATION, of each new DIRECTOR was approved by a
vote of at least two-thirds (2/3) of the DIRECTORS then still in office who were DIRECTORS at the beginning of the period; or
(c) the shareholders of the CORPORATION shall have approved (i) any consolidation or merger of the CORPORATION other than a merger or consolidation which would result in the voting securities of the CORPORATION outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70 percent of the Combined Voting Power of the CORPORATION, such surviving entity or the parent of such surviving entity outstanding immediately after the merger or consolidation; (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the CORPORATION, or (iii) any plan or proposal for the liquidation or dissolution of the CORPORATION. For purposes of this paragraph, the term Combined Voting Power shall mean the combined voting power of the CORPORATION's or other relevant entity's then outstanding voting securities.
17. Listing and Registration of Shares
Each OPTION shall be subject to the requirement that if at any time the COMMITTEE shall determine, in its discretion, that the listing, registration or qualification of the shares covered thereby under any securities exchange or under any state or federal law or the consent or approval of any governmental regulatory body, including the California Public Utilities Commission, is necessary or desirable as a condition of, or in connection with, the granting of such OPTION or the issue or purchase of shares thereunder, such OPTION may not be exercised in whole or in part unless and until such listing, registration, qualification, consent or approval shall have been effected or obtained free of any conditions not acceptable to the COMMITTEE.
18. Amendment and Termination of the Plan and Options
The BOARD OF DIRECTORS or the COMMITTEE may at any time suspend, terminate, modify or amend the PLAN in any respect; provided, however, that, to the extent necessary and desirable to comply with Section 422 of the CODE (or any other applicable law or regulation, including the requirements of any stock exchange on which the COMMON STOCK is listed or quoted), shareholder approval of any PLAN amendment shall be obtained in such a manner and to such a degree as is required by the applicable law or regulation.
No suspension, termination, modification or amendment of the PLAN may, without the consent of the OPTIONEE, adversely affect his or her rights under OPTIONS theretofore granted to such OPTIONEE. In the event of amendments to the CODE or applicable rules or regulations relating to ISOS subsequent to the date hereof, the CORPORATION may amend the PLAN, and the CORPORATION and OPTIONEES holding OPTION agreements may agree to amend outstanding OPTION agreements, to conform to such amendments.
The COMMITTEE may make such amendments or modifications in the terms and conditions of any OPTION as it may deem advisable, or cancel or annul any grant of an OPTION; provided, however, that no such amendment, modification, cancellation or annulment may, without the consent of the OPTIONEE, adversely affect his or her rights under such OPTION; and provided further the COMMITTEE may not reduce the OPTION PRICE or purchase price of any OPTION or OPTION below the original OPTION PRICE or purchase price.
Notwithstanding the foregoing, the COMMITTEE reserves the right, in its sole
discretion, to (i) convert any outstanding ISOS to NON-QUALIFIED STOCK OPTIONS,
(ii) to require a OPTIONEE to forfeit any unexercised or securities unpurchased
OPTIONS, any shares received or purchased pursuant to an OPTION, or any gains
realized by virtue of the receipt of an OPTION in the event that such OPTIONEE
competes against the CORPORATION, and (iii) to cancel or annul any grant of an
OPTION in the event of a OPTIONEE'S TERMINATION FOR CAUSE. For purposes of the
PROGRAM, "TERMINATION FOR CAUSE" shall include, but not be limited to,
termination because of dishonesty, criminal offense or violation of a work rule,
and shall be determined by, and in the sole discretion of, the COMMITTEE.
19. Effective Date of the Plan and Duration
The PLAN first became effective as of January 1, 1992. It has since been amended and restated. The amended and restated PLAN became effective as of January 1, 1996, upon approval by the shareholders of Pacific Gas and Electric Company at its
Annual Meeting on April 17, 1996. Effective January 1, 1997, the PLAN was assumed by PG&E CORPORATION. The PLAN was subsequently amended on October 21, 1998, April 21, 1999, February 16, 2000, and September 19, 2000. Effective May 16, 2001, the PLAN, and the PROGRAM of which the PLAN is a part, were amended to add 15,000,000 shares of COMMON STOCK to the total number of shares of COMMON STOCK reserved for use under the PLAN and the PROGRAM. Unless terminated sooner pursuant to Section 18 hereof, the PLAN shall terminate on December 31, 2005.
20. Definitions
(a) BOARD OF DIRECTORS means the Board of Directors of PG&E CORPORATION.
(b) CHANGE IN CONTROL has the meaning set forth in Section 16 hereof.
(c) CHIEF EXECUTIVE OFFICER means the Chief Executive Officer of PG&E
CORPORATION.
(d) CODE means the Internal Revenue Code of 1986, as amended from time to time.
(e) COMMITTEE means the Nominating and Compensation Committee of the BOARD OF DIRECTORS or any successor to such committee.
(f) COMMON STOCK means common shares of PG&E CORPORATION with no par value and any class of common shares into which such common shares hereafter may be converted.
(g) CONSULTANT means any person, including an advisor, who is engaged by the CORPORATION to render services.
(h) CORPORATION means PG&E CORPORATION, and any parent corporation (as defined in Section 424(e) of the CODE) or subsidiary corporation (as defined in Section 424(f) of the CODE).
(i) DEA means a Dividend Equivalent Account described in Section 9 hereof.
(j) DIRECTOR means any person who is a member of the BOARD OF DIRECTORS or the Board of Directors of any parent corporation (as defined in Section 424(e) of the CODE) which may hereafter be established, including an advisory, emeritus or honorary director.
(k) DIVIDEND EQUIVALENT means a right that entitles the OPTIONEE to receive cash or COMMON STOCK based on the dividends declared on the COMMON STOCK covered by such right.
(l) ELIGIBLE PARTICIPANT means any KEY EMPLOYEE. It also means, if so identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the case of OPTIONS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), other EMPLOYEES, DIRECTORS, CONSULTANTS, employees or consultants of any affiliates of PG&E CORPORATION, and other persons whose participation in the PROGRAM is deemed by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the case of OPTIONS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof) to be in the best interests of the CORPORATION; provided, however, that DIRECTORS who are not EMPLOYEES shall not be ELIGIBLE PARTICIPANTS for purposes of the PLAN.
(m) EMPLOYEE means any person who is employed by the CORPORATION. The payment of a director's fee or consulting fee by the CORPORATION shall not be sufficient to constitute "employment" by the CORPORATION.
(n) ERISA means the Employee Retirement Income Security Act of 1974, as amended.
(o) EXCHANGE ACT means the Securities Exchange Act of 1934, as amended.
(p) FAIR MARKET VALUE means the closing price of the COMMON STOCK reported on the New York Stock Exchange Composite Transactions for the date specified for determining such value.
(q) ISO means an OPTION intended to qualify as an incentive stock option under
Section 422 of the CODE.
(r) KEY EMPLOYEE means the Corporate Secretary, Treasurer, Vice Presidents and other executive officers of PG&E CORPORATION above the rank of Vice President. It also means, if so identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the case of OPTIONS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), executive officers of wholly-owned subsidiaries of PG&E CORPORATION (including subsidiaries which become such after adoption of the PROGRAM) and any other key management employee of PG&E CORPORATION or any wholly-owned subsidiary of PG&E CORPORATION.
(s) NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE.
(t) NON-QUALIFIED STOCK OPTION means any OPTION which is not an ISO.
(u) OPTION means an option to purchase shares of COMMON STOCK granted under the PLAN.
(v) OPTIONEE means the ELIGIBLE PARTICIPANT receiving the OPTION, or his or her legal representative, legatees, distributees or alternate payees, as the case may be.
(w) OPTION PRICE means the purchase price for the COMMON STOCK upon exercise of an OPTION.
(x) PG&E CORPORATION means PG&E CORPORATION, a California corporation.
(y) PLAN means this Stock Option Plan as amended and restated herein and as may be amended from time to time, or any successor plan which the COMMITTEE may adopt from time to time with respect to the grant of OPTIONS under the PROGRAM.
(z) PROGRAM means the PG&E Corporation Long-Term Incentive Program, as amended effective as of May 16, 2001, and as may be amended from time to time, pursuant to which the PLAN is adopted.
(aa) RETIREMENT means termination of employment with the CORPORATION at age 55 or later, provided that the ELIGIBLE PARTICIPANT was employed by the CORPORATION for at least five consecutive years prior to the date of termination.
(bb) RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor to Rule 16b-3, as in effect when discretion is being exercised with respect to the PLAN.
(cc) SAR means a stock appreciation right whose value is based on the increase in the FAIR MARKET VALUE of the COMMON STOCK covered by such right.
(dd) SECTION 16 OFFICER means any person who is designated by the BOARD OF DIRECTORS as an executive officer of PG&E CORPORATION and any other person who is designated as an officer of PG&E CORPORATION for purposes of Section 16 of the EXCHANGE ACT.
(ee) TANDEM refers to a DIVIDEND EQUIVALENT or SAR (as the case may be) granted in conjunction with an OPTION.
(ff) TERMINATION occurs when an EMPLOYEE ceases to be employed by the CORPORATION as a common law employee, when a DIRECTOR ceases to be a member of the BOARD OF DIRECTORS or the Board of Directors of any parent corporation which may hereafter be established (as the case may be), or when the relationship between the CORPORATION and a CONSULTANT or other ELIGIBLE PARTICIPANT terminates, as the case may be.
(gg) TERMINATION FOR CAUSE has the meaning set forth in Section 12 hereof.
EXHIBIT B
PG&E CORPORATION
PERFORMANCE UNIT PLAN
This is the controlling and definitive statement of the Performance Unit Plan ("PLAN") for ELIGIBLE EMPLOYEES of PG&E CORPORATION ("CORPORATION") and such other companies, affiliates, subsidiaries, or associations as the BOARD OF DIRECTORS may designate from time to time. The PLAN was first adopted by the BOARD in 1989 and was effective January 1, 1990. It has since been amended from time to time, most recently on September 19, 2000. Effective May 16, 2001, the PLAN, and the PROGRAM of which the PLAN is a part, was amended to add 15,000,000 shares of COMMON STOCK to the total number of shares of COMMON STOCK reserved for use under the PLAN and the PROGRAM.
ARTICLE I
DEFINITIONS
1.01 Board of Directors or Board shall mean the BOARD OF DIRECTORS of the CORPORATION or, when appropriate, any committee of the BOARD which has been delegated the authority to take action with respect to the PLAN.
1.02 Committee shall mean the Nominating and Compensation Committee of the BOARD
OF DIRECTORS.
1.03 Corporation shall mean PG&E CORPORATION, a California corporation.
1.04 Eligible Employee shall mean employees of the CORPORATION who are officers at the vice presidential level or above, the corporate secretary, the controller, and the treasurer of the CORPORATION, and such other employees of the CORPORATION, other companies, affiliates, subsidiaries, or associations as may be designated by the COMMITTEE.
1.05 Performance Targets shall mean the annual CORPORATION financial and operational goals adopted by the COMMITTEE to be used in determining awards under the PLAN.
1.06 Plan shall mean the Performance Unit Plan ("PUP") as set forth herein and as may be amended from time to time.
1.07 Plan Administrator shall mean the COMMITTEE or such individual or individuals as that COMMITTEE may appoint to handle the day-to-day affairs of the PLAN.
1.08 Price shall mean the average market price of STOCK for the last 30-day period of the YEAR preceding the YEAR in which UNITS are payable.
1.09 PUP Units shall mean the units granted to ELIGIBLE EMPLOYEES who participate in the PLAN. A PUP UNIT has the equivalent value of the current market price of a share of STOCK at the time of grant.
1.10 Retirement means termination of employment with the CORPORATION at age 55 or later, provided that the ELIGIBLE EMPLOYEE was employed by the CORPORATION for at least five consecutive years prior to the date of termination.
1.11 Stock shall mean the common stock of the CORPORATION and any class of common shares into which such STOCK hereafter may be converted.
1.12 Vesting Period shall mean the three calendar YEARS commencing with the YEAR in which PUP UNITS are granted.
1.13 Year shall mean a calendar year.
ARTICLE II
2.01 Prior to the beginning of each YEAR, the COMMITTEE shall determine whether PUP UNITS will be granted for such YEAR, the ELIGIBLE EMPLOYEES to whom PUP UNITS will be granted, and the number of PUP UNITS to be granted to each ELIGIBLE EMPLOYEE. Employees who become ELIGIBLE EMPLOYEES after the beginning of a YEAR shall be entitled to a prorata grant of PUP UNITS.
2.02 At the same time that the COMMITTEE makes its determination as to the granting of PUP UNITS, it shall also establish PERFORMANCE TARGETS. Although it is intended that PERFORMANCE TARGETS will not change in the course of the YEAR, the COMMITTEE reserves the right to modify or adjust a previously set PERFORMANCE TARGET if, in its sole discretion, extraordinary events warrant such modification or adjustment; provided, however, that no such modification or adjustment shall increase the amount of any payment that would otherwise be due based upon performance as measured against the original PERFORMANCE TARGET.
2.03 Each grant of PUP UNITS shall have its own VESTING PERIOD. Subject to modification as measured against a given YEAR's applicable PERFORMANCE TARGET, each grant of PUP UNITS shall be payable as follows:
a. One-third after the end of the first YEAR of the VESTING PERIOD;
b. One-third after the end of the second YEAR of the VESTING PERIOD; and
c. One-third after the end of the third YEAR of the VESTING PERIOD.
2.04 To determine the number of PUP UNITS earned, the applicable PERFORMANCE TARGET shall be the PERFORMANCE TARGET for the YEAR in which the PUP UNITS vest. Performance as measured against the applicable PERFORMANCE TARGET for a YEAR shall modify all PUP UNITS that vest at the end of such YEAR. The PERFORMANCE TARGETS established by the COMMITTEE may modify the number of UNITS earned from 0% to 200% of the number of vested UNITS.
2.05 ELIGIBLE EMPLOYEES shall receive a cash payment as soon as practicable
following the YEAR PUP UNITS vest pursuant to the schedule set forth in Section
2.03. The amount of the payment shall be equal to the product of the number of
PUP UNITS earned multiplied by the PRICE of STOCK.
2.06 Each time that the CORPORATION declares a dividend on its STOCK, an amount equal to the dividend multiplied by an ELIGIBLE EMPLOYEE's outstanding, but unearned PUP UNITS, shall be accrued on behalf of each ELIGIBLE EMPLOYEE. As soon as practicable following the end of each YEAR, ELIGIBLE EMPLOYEES shall receive a cash payment of the dividends accrued for that YEAR, modified by performance for that YEAR as measured under Section 2.04.
2.07 An ELIGIBLE EMPLOYEE may elect to defer the payment of PUP UNITS and/or dividends paid on PUP UNITS by making a timely election under the Deferred Compensation Plan. Deferrals of benefits payable under this Plan shall be subject to the rules contained in the Deferred Compensation Plan governing elections to defer and receipt of deferred amounts.
ARTICLE III
3.01 Retirement. Upon RETIREMENT, all outstanding PUP UNITS continue to be payable according to the terms of the PLAN. Thus, the number of UNITS eventually earned by a retired employee is still subject to modification depending on the extent to which applicable PERFORMANCE TARGETS are met during the YEAR preceding the January in which UNITS become payable under the schedule of Section 2.03. A retired employee is not entitled to receive grants of PUP UNITS after RETIREMENT.
3.02 Disability. If an ELIGIBLE EMPLOYEE is both disabled and entitled to receive benefits under Pacific Gas and Electric Company's Long Term Disability Plan, UNITS granted prior to the date of disability shall continue to be payable according to the terms of this PLAN. An ELIGIBLE EMPLOYEE is not entitled to receive grants of PUP UNITS after the date of disability as determined under the provisions of the Long Term Disability Plan. If an ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE EMPLOYEE because of disability and is not entitled to receive benefits under Pacific Gas and Electric Company's Long Term Disability Plan, all outstanding grants of PUP UNITS become vested and payable as soon as practicable in the YEAR following
the YEAR in which the ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE EMPLOYEE. All of the UNITS payable shall be subject to modification based upon performance as measured against the PERFORMANCE TARGET for the YEAR in which the ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE EMPLOYEE.
3.03 Death. In the event of the death of an ELIGIBLE EMPLOYEE, all outstanding grants of PUP UNITS held by the ELIGIBLE EMPLOYEE at the date of death shall become vested and payable as soon as practicable in the YEAR following the YEAR of death. All of the UNITS payable after an ELIGIBLE EMPLOYEE's death shall be subject to modification based upon performance as measured against the PERFORMANCE TARGET for the YEAR in which the death of the ELIGIBLE EMPLOYEE occurs.
3.04 Termination. If an ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE EMPLOYEE for any reason other than RETIREMENT, disability, or death, all outstanding grants of PUP UNITS shall be canceled as of the date that the ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE EMPLOYEE unless otherwise provided in the PG&E Corporation Officer Severance Policy.
3.05 Change in Control. Upon a Change in Control as defined in the PG&E Corporation Long Term Incentive Program (Program) or upon a termination of employment coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, all PUP UNITS shall become vested and payable as soon as practicable in the YEAR following the Change in Control in accordance with Section 16 of the Program.
ARTICLE IV
ADMINISTRATIVE PROVISIONS
4.01 Administration. The PLAN shall be administered by the PLAN ADMINISTRATOR who shall have the authority to interpret the PLAN and make such rules as it deems appropriate. The PLAN ADMINISTRATOR shall have the duty and responsibility of maintaining records, making the requisite calculations, and disbursing payments hereunder. The PLAN ADMINISTRATOR's interpretations, determinations, rules, and calculations shall be final and binding on all persons and parties concerned.
4.02 Amendment and Termination. The CORPORATION may amend or terminate the PLAN at any time, provided, however, that no such amendment or termination shall adversely affect PUP UNITS which an ELIGIBLE EMPLOYEE has earned prior to the date of such amendment or termination. PUP UNITS outstanding but unearned at the date of any such amendment or termination may, in the sole discretion of the CORPORATION, be canceled, and the CORPORATION shall have no obligation to provide a substitute benefit of lesser, equal, or greater value.
4.03 Nonassignability of Benefits. The benefits payable under this PLAN or the right to receive future benefits under this PLAN may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a person eligible for any benefits becomes bankrupt, the interest under the PLAN of the person affected may be terminated by the PLAN ADMINISTRATOR which, in its sole discretion, may cause the same to be held if applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that it deems appropriate.
4.04 No Guarantee of Employment. Nothing contained in this PLAN shall be construed as a contract of employment between the CORPORATION or the ELIGIBLE EMPLOYEE, or as a right of the ELIGIBLE EMPLOYEE to be continued in the employ of the CORPORATION, to remain as an officer of the CORPORATION, or as a limitation on the right of the CORPORATION to discharge any of its employees, with or without cause.
4.05 Benefits Unfunded and Unsecured. The benefits under this PLAN are unfunded, and the interest under this PLAN of any ELIGIBLE EMPLOYEE and such ELIGIBLE EMPLOYEE's right to receive a distribution of benefits under this PLAN shall be an unsecured claim against the general assets of the CORPORATION.
4.06 Applicable Law. All questions pertaining to the construction, validity, and effect of the PLAN shall be determined in accordance with the laws of the United States, and to the extent not preempted by such laws, by the laws of the State of California.
EXHIBIT C
PG&E CORPORATION
NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN
(As amended effective as of May 16, 2001)
1. Purpose of the Plan
This is the controlling and definitive statement of the PG&E Corporation Non- Employee Director Stock Incentive Plan (hereinafter called the PLAN). The purpose of the PLAN is to advance the interests of the CORPORATION by providing NON-EMPLOYEE DIRECTORS with financial incentives to promote the success of its long-term (five to ten years) business objectives, and to increase their proprietary interest in the success of the CORPORATION. Inasmuch as the PLAN is designed to encourage financial performance and to improve the value of shareholders' investment in PG&E CORPORATION, the costs of the PLAN will be funded from corporate earnings.
2. Formula Awards of Director Restricted Stock, Non-Qualified Stock Options and Phantom Stock to Non-Employee Directors
All awards of DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK under the PLAN shall be automatic and non-discretionary, and shall be made strictly in accordance with the provisions contained herein. No person shall have any discretion to select which NON-EMPLOYEE DIRECTORS shall be granted DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS or PHANTOM STOCK. Further, no person shall have any discretion to determine the number of shares of DIRECTOR RESTRICTED STOCK awarded to a NON-EMPLOYEE DIRECTOR, and, except as otherwise provided in Section 4 with respect to a NON-EMPLOYEE DIRECTOR'S election to allocate formula awards between NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK, no person shall have any discretion to determine the number of shares underlying NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK awarded to a NON-EMPLOYEE DIRECTOR.
3. Awards of Director Restricted Stock
(a) On the first business day of each calendar year beginning on January 1, 1998, during the duration of the PLAN, each person who is a NON-EMPLOYEE DIRECTOR on the first business day of the applicable calendar year shall receive a grant of DIRECTOR RESTRICTED STOCK in an amount to be determined in accordance with the formula set forth in this Section 3(a). The number of shares of DIRECTOR
RESTRICTED STOCK to be granted to each NON-EMPLOYEE DIRECTOR each calendar year shall be determined by (i) dividing ten thousand dollars ($10,000) by the FAIR MARKET VALUE of the COMMON STOCK on the first business day of the applicable calendar year, and (ii) rounding the resulting number down to the nearest whole share. No person shall receive more than one (1) grant of DIRECTOR RESTRICTED STOCK during any calendar year.
(b) Shares of DIRECTOR RESTRICTED STOCK shall vest cumulatively as follows: (i) twenty percent (20%) of such shares on the first anniversary of the date of grant; (ii) forty percent (40%) of such shares on the second anniversary of the date of grant; (iii) sixty percent (60%) of such shares on the third anniversary of the date of grant; (iv) eighty percent (80%) of such shares on the fourth anniversary of the date of grant; and (v) one hundred percent (100%) of such shares on the fifth anniversary of the date of grant. Shares of DIRECTOR RESTRICTED STOCK may not be resold or otherwise transferred by a GRANTEE until such shares are vested in accordance with the provisions of this Section 3(b).
4. Annual Election to Receive Non-Qualified Stock Options and Phantom Stock
By June 30 of each calendar year during the term of the Plan, each person who is then a NON-EMPLOYEE DIRECTOR shall deliver to the Corporate Secretary a written election to receive either NON-QUALIFIED STOCK OPTIONS or PHANTOM
STOCK, or both, with an aggregate value of $20,000, on the first business day of
the following calendar year, provided the person continues to be a NON-EMPLOYEE
DIRECTOR on the date the award would otherwise be made. A NON-EMPLOYEE DIRECTOR
may allocate between NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK in minimum
increments with a value equal to $5,000, as determined in accordance with
Section 5 below with respect to NON-QUALIFIED STOCK OPTIONS, and Section 6
below, with respect to PHANTOM STOCK. All awards of NON-QUALIFIED STOCK OPTIONS
and PHANTOM STOCK made to NON-EMPLOYEE DIRECTORS shall comply with Section 5 and
Section 6 below, respectively. A NON-EMPLOYEE DIRECTOR who has failed to make a
timely election or who became a NON-EMPLOYEE DIRECTOR after June 30 shall be
awarded NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK, each with a value of
$10,000 as determined in accordance with Section 5 and Section 6, respectively,
provided that the NON-EMPLOYEE DIRECTOR continues to be a NON-EMPLOYEE DIRECTOR
on the on the first business day of the following calendar year. Notwithstanding
the foregoing, elections for calendar year 1998 must be received by December 31,
1997, to be effective on the first business day of calendar year 1998.
5. Grant of Non-Qualified Stock Options to Non-Employee Directors
(a) On the first business day of each calendar year beginning on January 1, 1998, during the duration of the PLAN, each person who is then a NON-EMPLOYEE DIRECTOR and who has elected to receive an award of NON-QUALIFIED STOCK OPTIONS in accordance with Section 4, shall receive a grant of NON-QUALIFIED STOCK OPTIONS with an aggregate value equal to $5,000, $10,000, $15,000, or $20,000, as previously elected by the NON-EMPLOYEE DIRECTOR (or $10,000 in the case of a NON-EMPLOYEE DIRECTOR who has failed to make a timely election in accordance with Section 4 or who became a NON-EMPLOYEE DIRECTOR after June 30) (the "Elected Option Value"). The number of shares subject to the NON-QUALIFIED STOCK OPTIONS shall be determined by dividing the Elected Option Value by the value of a NON-QUALIFIED STOCK OPTION to purchase a single share of PG&E Corporation common stock as of the first business day of the applicable calendar year. The per stock option value shall be calculated in accordance with the Black-Scholes stock option valuation method using the average preceding November closing price of PG&E Corporation stock and reducing the per option value so calculated by twenty percent. The resulting number of NON-QUALIFIED STOCK OPTIONS shall be rounded down to the nearest whole share. No person shall receive more than one grant of NON-QUALIFIED STOCK OPTIONS during any calendar year.
(b) The OPTION PRICE of the COMMON STOCK subject under each NON-QUALIFIED STOCK OPTION shall be the FAIR MARKET VALUE of the COMMON STOCK on the date of grant. The exercise of any NON-QUALIFIED STOCK OPTION shall be contingent upon receipt by the CORPORATION of (i) cash, (ii) check, (iii) shares of COMMON STOCK, (iv) an executed exercise notice together with irrevocable instructions to a broker to either sell the shares subject to the NON-QUALIFIED STOCK OPTION or hold such shares as collateral for a margin loan and to promptly deliver to the CORPORATION the amount of sale or loan proceeds required to pay the OPTION PRICE, or (v) any combination of the foregoing in an amount equal to the full OPTION PRICE of the shares being purchased. For purposes of this paragraph, shares of COMMON STOCK that are delivered in payment of the OPTION PRICE must have been previously owned by the GRANTEE for a minimum of one year, and shall be valued at their FAIR MARKET VALUE as of the date of the exercise of the NON- QUALIFIED STOCK OPTION. The CORPORATION shall not make loans to any GRANTEE for the purpose of exercising NON-QUALIFIED STOCK OPTIONS.
(c) Each NON-QUALIFIED STOCK OPTION granted under the Plan shall become exercisable and vested cumulatively as follows: (i) up to thirty-three percent (33%) of the NON-QUALIFIED STOCK OPTION may be exercised on or after the second anniversary of the date of grant; (ii) up to sixty-six percent (66%) of the NON-QUALIFIED STOCK OPTION may be exercised on or after the third anniversary of the date of grant; and (iii) up to one hundred percent (100%) of the NON-QUALIFIED STOCK OPTION may be exercised on or after the fourth anniversary of the date of grant.
(d) The term of each NON-QUALIFIED STOCK OPTION shall be ten years and one day from the date of grant, subject to earlier termination as provided in Section 9 hereof. Any provision of the PLAN to the contrary notwithstanding, no NON- QUALIFIED STOCK OPTION shall be exercised after the time limitations stated in this Section 5(d).
6. Awards of Phantom Stock to Non-Employee Directors
(a) On the first business day of each calendar year beginning on January 1, 1998, during the duration of the PLAN, each person who is then a NON-EMPLOYEE DIRECTOR and who has elected to receive an award of PHANTOM STOCK
in accordance with Section 4, shall be credited with an amount of PHANTOM STOCK with a value (as determined by the FAIR MARKET VALUE of the COMMON STOCK on the first business day of the applicable calendar year) equal to $5,000, $10,000, $15,000, or $20,000, as previously elected by the NON-EMPLOYEE DIRECTOR (the "Elected Phantom Stock Value"). The number of shares of PHANTOM STOCK (including fractions computed to three decimal places) to be granted to each NON-EMPLOYEE DIRECTOR each calendar year shall be determined by dividing the Elected Phantom Stock Value (or $10,000 in the case of a NON-EMPLOYEE DIRECTOR who has failed to make a timely election in accordance with Section 4 or who became a NON-EMPLOYEE DIRECTOR after June 30) by the FAIR MARKET VALUE of the COMMON STOCK on the first business day of the applicable calendar year. No person shall receive more than one grant of PHANTOM STOCK during any calendar year. The shares of PHANTOM STOCK awarded to a NON-EMPLOYEE DIRECTOR shall be credited to a newly established PHANTOM STOCK account for the NON-EMPLOYEE DIRECTOR. Each share of PHANTOM STOCK shall be deemed to be equal to one share (or fraction thereof) of COMMON STOCK on the date of grant, and shall thereafter fluctuate in value in accordance with the FAIR MARKET VALUE of the COMMON STOCK.
(b) Each NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall be credited
quarterly on each dividend payment date with additional shares of PHANTOM STOCK
(including fractions computed to three decimal places) determined by dividing
(i) the aggregate amount of dividends, i.e,. the dividend multiplied by the
number of shares of PHANTOM STOCK credited to the participant's account as of
the dividend record date, by (ii) by the FAIR MARKET VALUE of the COMMON STOCK
on the dividend payment date.
(c) Payment of the shares of PHANTOM STOCK credited to a NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall only be made after the NON-EMPLOYEE DIRECTOR'S RETIREMENT or MANDATORY RETIREMENT from the BOARD OF DIRECTORS. Payment shall be made only in the form of shares of COMMON STOCK equal to the number of shares of PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account on the date of distribution, rounded down to the nearest whole share. The NON-EMPLOYEE DIRECTOR may elect to receive the number of shares of COMMON STOCK to which he is entitled in a lump sum distribution of the entire amount or in a series of ten or less approximately equal annual installments, provided that distribution shall commence no later than January of the year following the year in which the NON-EMPLOYEE DIRECTOR'S RETIREMENT or MANDATORY RETIREMENT occurred.
7. Shares of Stock Subject to the Plan
There shall be reserved for use under the PLAN and for the grant of any other INCENTIVE AWARDS pursuant to the PROGRAM (subject to the provisions of Section 10 hereof) a total of 49,389,230 shares of COMMON STOCK, which shares may be authorized but unissued shares of COMMON STOCK or issued shares of COMMON STOCK which shall have been reacquired by PG&E CORPORATION.
8. Dividend, Voting and Other Shareholder Rights
Except as otherwise provided in the PLAN, each GRANTEE shall have all of the rights of a shareholder of PG&E CORPORATION with respect to all outstanding shares of DIRECTOR RESTRICTED STOCK registered in his or her name, whether or not such shares are vested, including the right to receive dividends and other distributions paid or made with respect to such shares and the right to vote such shares. No GRANTEE shall have any of the rights of a shareholder of PG&E CORPORATION with respect to a NON-QUALIFIED STOCK OPTION until the shares acquired upon exercise of such NON-QUALIFIED STOCK OPTION have been issued and registered in his or her name. No GRANTEE shall have any of the rights of a shareholder of PG&E CORPORATION with respect to PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account under the Plan.
9. Termination of Status as a Non-Employee Director
(a) In the event of a TERMINATION by reason of disability or death,
(i) all shares of DIRECTOR RESTRICTED STOCK held by the GRANTEE shall become
fully vested, notwithstanding the provisions of Section 3(b) hereof, and the
GRANTEE (or the GRANTEE'S estate or a person who acquired the shares of DIRECTOR
RESTRICTED STOCK by bequest or inheritance) shall have the right to resell or
transfer such shares at any time, (ii) all NON-QUALIFIED STOCK OPTIONS held by
the GRANTEE, to the extent that such NON-QUALIFIED STOCK OPTIONS have not
previously expired or been exercised, shall become fully vested and exercisable, notwithstanding the provisions of Section 5(c) hereof, and the GRANTEE (or the GRANTEE'S estate or a person who acquired the right to exercise the NON- QUALIFIED STOCK OPTION by bequest or inheritance) shall have the right to exercise the NON-QUALIFIED STOCK OPTIONS at any time within their respective terms or within one (1) year after the date of the GRANTEE'S death or disability, whichever is shorter, and (iii) all shares of PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall immediately become payable to the GRANTEE (or the GRANTEE'S estate or a person who acquired the shares of PHANTOM STOCK by bequest or inheritance) in the form of a number of shares of COMMON STOCK equal to the number of shares of PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account, rounded down to the nearest whole share. The term "disability" shall, for the purposes of the PLAN, be defined in Section 22(e)(3) of the CODE.
(b) In the event of a TERMINATION by reason of MANDATORY RETIREMENT,
(i) all shares of DIRECTOR RESTRICTED STOCK held by the GRANTEE shall become
fully vested, notwithstanding the provisions of Section 3(b) hereof, and the
GRANTEE shall have the right to resell or transfer such shares at any time, (ii)
the NON-QUALIFIED STOCK OPTIONS then held by the GRANTEE, to the extent that
such NON-QUALIFIED STOCK OPTIONS have not previously expired or been exercised,
shall become fully vested and exercisable, notwithstanding the provisions of
Section 5(c) hereof, and the GRANTEE shall have the right to exercise the NON-
QUALIFIED STOCK OPTIONS at any time within their respective terms or within five
(5) years after such MANDATORY RETIREMENT, whichever is shorter; and (iii) all
shares of PHANTOM STOCK credited to the NON- EMPLOYEE DIRECTOR'S PHANTOM STOCK
account shall become payable to the GRANTEE in accordance with Section 6(c)
hereof.
(c) In the event of a TERMINATION for any reason other than those specified in subparagraphs (a) and (b) above, (i) any unvested shares of DIRECTOR RESTRICTED STOCK granted hereunder shall be forfeited and the GRANTEE shall return to the CORPORATION for cancellation any stock certificates representing such forfeited shares which forfeited shares shall be deemed to be canceled and no longer outstanding as of the date of TERMINATION; and from and after the date of TERMINATION, the GRANTEE shall cease to be a shareholder with respect to such forfeited shares and shall have no dividend, voting or other rights with respect thereto, (ii) any NON-QUALIFIED STOCK OPTIONS granted hereunder that have not yet vested and become exercisable shall terminate, (iii) the GRANTEE shall have the right to exercise NON-QUALIFIED STOCK OPTIONS, to the extent that such NON- QUALIFIED STOCK OPTIONS have vested and become exercisable as of the date of TERMINATION, at any time within their respective terms or within three months after such TERMINATION, whichever is shorter, after which the NON-QUALIFIED STOCK OPTIONS shall terminate, and (iv) all shares of PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall be forfeited on the date of TERMINATION; provided, however, that if the TERMINATION results from the NON- EMPLOYEE DIRECTOR'S RETIREMENT, then the PHANTOM STOCK credited to the NON- EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall become payable in accordance with Section 6(c) hereof.
(d) Notwithstanding the provisions of subparagraphs (a) through (c) above, the BOARD OF DIRECTORS may, in its sole discretion, establish different terms and conditions pertaining to the effect of TERMINATION, to the extent permitted by applicable federal and state law.
10. Adjustments Upon Changes in Number or Value of Shares of Common Stock
If there are any changes in the number or value of shares of COMMON STOCK by reason of stock dividends, stock splits, reverse stock splits, recapitalizations, mergers, consolidations or other events that materially increase or decrease the number or value of issued and outstanding shares of COMMON STOCK, the BOARD OF DIRECTORS or COMMITTEE may make such adjustments as it shall deem appropriate, in order to prevent dilution or enlargement of rights.
11. Non-Transferability
NON-QUALIFIED STOCK OPTIONS, PHANTOM STOCK, and shares of DIRECTOR RESTRICTED STOCK that have not vested in accordance with the provisions of Section 3(b) hereof, shall not be transferable by the GRANTEE otherwise than by will or the laws of descent and distribution, or pursuant to a qualified domestic relations order as defined by the CODE, Title I of ERISA or the rules thereunder.
12. Change in Control
Upon the occurrence of a CHANGE IN CONTROL (as defined below), (i) any time periods relating to the vesting of any shares of DIRECTOR RESTRICTED STOCK granted hereunder shall be accelerated so that all such shares immediately become fully vested, (ii) any time periods relating to the vesting of NON- QUALIFIED STOCK OPTIONS granted hereunder shall be accelerated so that all such NON-QUALIFIED STOCK OPTIONS immediately become fully vested and exercisable for the remainder of their terms, and (iii) all shares of PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTORS' PHANTOM STOCK accounts shall become payable in accordance with Section 6(c) hereof as if the CHANGE IN CONTROL constituted a RETIREMENT.
A "CHANGE IN CONTROL" shall be deemed to have occurred if:
(a) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or any trustee, agent or other fiduciary for any such plan acting in such person's capacity as such fiduciary), directly or indirectly, becomes the beneficial owner of securities of PG&E CORPORATION representing twenty percent (20%) or more of the combined voting power of PG&E CORPORATION's then outstanding securities;
(b) during any two consecutive years, individuals who at the beginning of such a period constitute the BOARD OF DIRECTORS cease for any reason to constitute at least a majority of the BOARD OF DIRECTORS, unless the election, or the nomination for election by the shareholders of PG&E CORPORATION, of each new DIRECTOR was approved by a vote of at least two-thirds (2/3) of the DIRECTORS then still in office who were DIRECTORS at the beginning of the period; or
the shareholders of the CORPORATION shall have approved (i) any consolidation or
merger of the CORPORATION other than a merger or consolidation which would
result in the voting securities of the CORPORATION outstanding immediately prior
thereto continuing to represent (either by remaining outstanding or by being
converted into voting securities of the surviving entity or any parent of such
surviving entity) at least 70 percent of the Combined Voting Power of the
CORPORATION, such surviving entity or the parent of such surviving entity
outstanding immediately after the merger or consolidation; (ii) any sale, lease,
exchange or other transfer (in one transaction or a series of related
transactions) of all or substantially all of the assets of the CORPORATION, or
(iii) any plan or proposal for the liquidation or dissolution of the
CORPORATION. For purposes of this paragraph, the term Combined Voting Power
shall mean the combined voting power of the CORPORATION's or other relevant
entity's then outstanding voting securities.
13. Amendment and Termination of the Plan
The BOARD OF DIRECTORS or the COMMITTEE may at any time suspend, terminate, modify or amend the PLAN in any respect; provided, however, that, to the extent necessary and desirable to comply with the CODE (or any other applicable law or regulation, including the requirements of any stock exchange on which the COMMON STOCK is listed or quoted), shareholder approval of any PLAN amendment shall be obtained in such a manner and to such a degree as is required by the applicable law or regulation.
No suspension, termination, modification or amendment of the PLAN may, without the consent of the GRANTEE, adversely affect his or her rights with respect to DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS or PHANTOM STOCK theretofore granted to such GRANTEE.
Except as provided in Section 2 hereof, the BOARD OF DIRECTORS or COMMITTEE may make such amendments or modifications in the terms and conditions of any grant of DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS or PHANTOM STOCK as it may deem advisable, or cancel or annul any grant of DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS or PHANTOM STOCK; provided, however, that no such amendment, modification, cancellation or annulment may, without the consent of the GRANTEE, adversely affect his or her rights with respect to such grant.
14. Effective Date of the Plan and Duration
This PLAN became effective as of January 1, 1996, upon approval by the shareholders of Pacific Gas and Electric Company at its Annual Meeting on April 17, 1996. Effective January 1, 1997, the PLAN was assumed by PG&E CORPORATION. At its
meeting on December 17, 1997, the BOARD OF DIRECTORS amended and restated the PLAN effective January 1, 1998, to (i) reflect the adoption of new RULE 16B-3 which became effective November 1, 1996, and (ii) provide automatic formula awards of NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK to NON-EMPLOYEE DIRECTORS within the limits of the PROGRAM as previously approved by shareholders in 1996. The PLAN was subsequently amended on October 21, 1998 and April 21, 1999.
Effective May 16, 2001, the PLAN, and the PROGRAM of which the PLAN is a part, were amended to add 15,000,000 shares of COMMON STOCK to the total number of shares of COMMON STOCK reserved for use under the PLAN and the PROGRAM. Unless terminated sooner pursuant to Section 13 hereof, the PLAN shall terminate on December 31, 2005.
15. Definitions
(a) BOARD OF DIRECTORS means the Board of Directors of PG&E CORPORATION.
(b) CHANGE IN CONTROL has the meaning set forth in Section 12 hereof.
(c) CODE means the Internal Revenue Code of 1986, as amended from time to time.
(d) COMMITTEE means the Nominating and Compensation Committee of the BOARD OF DIRECTORS or any successor to such committee.
(e) COMMON STOCK means common shares of PG&E CORPORATION with no par value and any class of common shares into which such common shares hereafter may be converted.
(f) CORPORATION means PG&E CORPORATION, and any parent corporation (as defined in Section 424(e) of the CODE) or subsidiary corporation (as defined in Section 424(f) of the CODE).
(g) DIRECTOR means any person who is a member of the BOARD OF DIRECTORS or the Board of Directors of any parent corporation (as defined in Section 424(e) of the CODE) which may hereafter be established, including an advisory, emeritus or honorary director.
(h) DIRECTOR RESTRICTED STOCK means RESTRICTED STOCK granted to a NON-EMPLOYEE
DIRECTOR under the PLAN.
(i) EMPLOYEE means any person who is employed by the CORPORATION. The payment of a director's fee or consulting fee by the CORPORATION shall not be sufficient to constitute "employment" by the CORPORATION.
(j) ERISA means the Employee Retirement Income Security Act of 1974, as amended.
(k) EXCHANGE ACT means the Securities Exchange Act of 1934, as amended.
(l) FAIR MARKET VALUE means the closing price of the COMMON STOCK reported on the New York Stock Exchange Composite Transactions for the date specified for determining such value.
(m) GRANTEE means the NON-EMPLOYEE DIRECTOR receiving the DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK or his or her legal representative, legatees, distributees or alternate payees, as the case may be.
(n) MANDATORY RETIREMENT means retirement as a DIRECTOR at age 70 or at such other age as may be specified in the retirement policy for the BOARD OF DIRECTORS or the Board of Directors of any parent corporation which may hereafter be established (as the case may be), as in effect at the time of a NON-EMPLOYEE DIRECTOR'S TERMINATION.
(o) NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE.
(p) NON-QUALIFIED STOCK OPTION means a option to purchase shares of COMMON
STOCK which is not intended to qualify as an incentive stock option under
Section 422 of the CODE.
(q) PG&E CORPORATION means PG&E CORPORATION, a California corporation.
(r) PHANTOM STOCK means allocated hypothetical shares of COMMON STOCK that can be converted at a future date into stock.
(s) PLAN means this Non-Employee Director Stock Incentive Plan, as may be amended from time to time, or any successor plan which the COMMITTEE or BOARD OF DIRECTORS may adopt from time to time with respect to the grant of DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS, PHANTOM STOCK or other stock- based incentive awards under the PROGRAM.
(t) PROGRAM means the PG&E Corporation Long-Term Incentive Program, as amended effective May 16, 2001, and as may be amended from time to time, pursuant to which this PLAN is adopted.
(u) RESTRICTED STOCK means COMMON STOCK that is subject to forfeiture by the GRANTEE to the CORPORATION under such circumstances as may be specified by the COMMITTEE.
(v) RETIREMENT means TERMINATION of service on the BOARD OF DIRECTORS after serving continuously for five consecutive years.
(w) RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor to Rule 16b-3, as in effect when discretion is being exercised with respect to the PLAN.
TERMINATION occurs when a NON-EMPLOYEE DIRECTOR ceases to be a member of the BOARD OF DIRECTORS or the Board of Directors of any parent corporation which may hereafter be established (as the case may be).
EXHIBIT 11
PG&E CORPORATION
COMPUTATION OF EARNINGS PER COMMON SHARE
Three months Six months
ended June 30, ended June 30,
--------------- ----------------
(in millions, except per share amounts) 2001 2000 2001 2000
------ ------ ------ ------
EARNINGS (LOSS) PER COMMON SHARE, BASIC (1)
Earnings available for common stock $ 750 $ 248 $ (201) $ 528
--- --- --- ---
Weighted average common shares outstanding (2) 363 361 363 361
--- --- --- ---
Earnings (Loss) per common share $ 2.07 $ .69 $ (.55) $ 1.46
==== ==== ==== ====
EARNINGS (LOSS) PER COMMON SHARE, DILUTED (1)
Earnings available for common stock $ 750 $ 248 $ (201) $ 528
--- --- --- ---
Weighted average common shares outstanding (2) 363 361 363 361
Add: Outstanding options, reduced by the number of shares that could be
repurchased with the proceeds from such exercise (at average market price)
(3) - 3 - 2
--- --- --- ---
Shares outstanding for diluted calculation 363 364 363 363
--- --- --- ---
Earnings (Loss) per common share $ 2.07 $ .68 $ (.55) $ 1.45
==== ==== ==== ====
|
(1) This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K and Statement of Financial Accounting Standards No. 128.
(2) Average common shares outstanding exclude shares held by a subsidiary of PG&E Corporation (23,815,500 shares at June 30, 2000 and 2001, respectively) and shares held by PG&E Corporation to secure deferred compensation obligations (281,985 shares at June 30, 2000 and 2001, respectively).
(3) The diluted share base for the six months ended June 30, 2001 excludes incremental shares of approximately 290 thousand related to employee stock options and deferred compensation obligations. These shares are excluded due to the antidilutive effects of the net loss.
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY
A DEBTOR-IN-POSSESSION
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
Six months
ended June 30, Year ended December 31,
-------------- -------------------------------------------
(dollars in millions) 2001 2000 1999 1998 1997 1996
-------------------------------------------------------------
Earnings:
Net income (loss) $ (292) $(3,483) $ 788 $ 729 $ 768 $ 755
Adjustments for minority interest
in losses of less than 100% owned
affiliates and the Company's
equity in undistributed income
(losses) of less than 50% owned
affiliates - - - - - 3
Income tax expense (200) (2,154) 648 629 609 555
Net fixed charges 481 648 637 673 628 683
----- ------ ----- ----- ----- -----
Total Earnings (11) (4,989) 2,073 2,031 2,005 1,996
===== ====== ===== ===== ===== =====
Fixed Charges:
Interest on short-term borrowings
and long-term debt, net 462 616 604 635 586 649
Interest on capital leases 1 2 3 2 2 3
AFUDC debt 6 6 7 12 17 8
Earnings required to cover the
preferred stock dividend and
preferred security distribution
requirements of majority owned 12 24 24 24 24 24
trust ----- ------ ----- ----- ----- -----
Total Fixed Charges $ 481 $ 648 $ 638 $ 673 $ 629 $ 684
===== ====== ===== ===== ===== =====
Ratios of Earnings to Fixed
Charges (0.02)(1) (7.70)(1) 3.25 3.02 3.19 2.92
===== ====== ===== ===== ===== =====
|
Note:
For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to fixed charges, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, cash distributions from and equity in undistributed income or loss of Pacific Gas and Electric Company's less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest of subordinated debentures held by trust, interest on capital leases, and earnings required to cover the preferred stock dividend requirements.
(1) The ratio of earnings to fixed charges indicates a deficiency of less than one-to-one coverage aggregating $492 million for the six months ended June 30,2001, and $5,637 million for the twelve months ended December 31,2000.
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY
A DEBTOR-IN-POSSESSION
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED
FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
Six months
ended June 30, Year ended December 31,
-------------- ----------------------------------------
(dollars in millions) 2001 2000 1999 1998 1997 1996
--------------------------------------------------------
Earnings:
Net income (loss) $ (292) $(3,483) $ 788 $ 729 $ 768 $ 755
Adjustments for minority interest
in losses of less than 100% owned
affiliates and the Company's
equity in undistributed income
(losses) of less than 50% owned
affiliates - - - - - 3
Income tax expense (200) (2,154) 648 629 609 555
Net fixed charges 481 648 637 673 628 683
----- ------ ----- ----- ----- -----
Total Earnings (11) (4,989) 2,073 2,031 2,005 1,996
===== ===== ===== ===== ===== =====
Fixed Charges:
Interest on short-term
borrowings and long-term debt, net 462 616 604 635 586 649
Interest on capital leases 1 2 3 2 2 3
AFUDC debt 6 6 7 12 17 8
Earnings required to cover the
preferred stock dividend and
preferred security distribution
requirements of majority owned 12 24 24 24 24 24
trust ----- ------ ----- ----- ----- -----
Total Fixed Charges 481 648 638 673 629 684
===== ====== ===== ===== ===== =====
Preferred Stock Dividends:
Tax deductible dividends 4 9 9 9 10 10
Pretax earnings required to cover
non-tax deductible preferred
stock dividend requirements 14 27 27 31 39 39
----- ------ ----- ----- ----- -----
Total Preferred Stock Dividends 18 36 36 40 49 49
----- ------ ----- ----- ----- -----
Total Combined Fixed Charges and
Preferred Stock Dividends $ 499 $ 684 $ 674 $ 713 $ 678 $ 733
===== ====== ===== ===== ===== =====
Ratios of Earnings to Combined
Fixed and Preferred Stock (0.02)(1) (7.29)(1) 3.08 2.85 2.96 2.72
Dividend ===== ===== ===== ===== ===== =====
|
Note:
For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to combined fixed charges and preferred stock dividends, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, cash distributions from and equity in undistributed income or loss of Pacific Gas and Electric Company's less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, interest of subordinated debentures held by trust, and earnings required to cover the preferred stock dividend requirements of majority owned subsidiaries. "Preferred stock dividends" represent pretax earnings, which would be required to cover such dividend requirements.
(1) The ratio of earnings to combined fixed charges and preferred stock dividends indicates a deficiency of less than one-to-one coverage aggregating $510 million for the six months ended June 30,2001, and $5,673 million for the twelve months ended December 31,2000.