PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY,
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED ~~MARCH 31,~~JUNE 30, 2003
TABLE OF CONTENTS

PG&E Corporation was incorporated in California in 1995 and became the holding company of Pacific Gas and Electric Company (Utility), a debtor-in-possession, ~~(the Utility),~~ and its subsidiaries on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. The Utility delivers electric service to approximately 4.8 million customers and natural gas service to approximately ~~4.0~~3.9 millioncustomers in Northern and Central California. Both PG&E Corporation and the Utility are headquartered in San Francisco. As discussed further in Note 2, on April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the ~~U.S.~~federal Bankruptcy Code (Bankruptcy Code) in the U.S. Bankruptcy Court for the Northern District of California ~~(Bankruptcy Court)~~(referred to as the "Bankruptcy Court" in this report's discussion of the Utility's Chapter 11 filing). Pursuant to Chapter 11, the Utility retains control of its assets and is authorized to ~~operate~~oper ate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court.

PG&E Corporation's other significant subsidiary is PG&E National Energy Group, Inc. (PG&E NEG) and its subsidiaries, headquartered in Bethesda, Maryland. PG&E NEG was incorporated on December 18, 1998, as a ~~wholly-owned~~wholly owned subsidiary of PG&E Corporation. ~~Shortly thereafter,~~ PG&E ~~Corporation contributed various subsidiaries to PG&E NEG. PG&E NEG's principal subsidiaries include:~~

natural gas transmission in the United States of America. During February and March of 2003, certain lenders of PG&E Corporation exercised options to purchase 3 percent of the shares of PG&E NEG. No gain or loss was recognized by PG&E Corporation ~~upon~~for this transaction.

~~The Consolidated Financial Statements of PG&E Corporation and of the Utility have been prepared~~ As discussed further in Note 3, on a going concern basis, which contemplates continuity of operations, realization of assets, and repayment of liabilities in the ordinary course of business. However, as a result of the bankruptcy of the Utility and current liquidity concerns at PG&E NEG and its subsidiaries, as further discussed below, such realization of assets and liquidation of liabilities are subject to uncertainty.

PG&E NEG currently is focused on power generation and natural gas transmission in the United States. As a result of the sustained downturn in the power industry, PG&E NEG and its affiliates have experienced a financial downturn, which caused the major credit rating agencies to downgrade PG&E NEG's and its affiliates' credit ratings in the second half of 2002 to below investment grade. PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling $2.7 billion, but this debt is non-recourse to PG&E NEG.

PG&E NEG, its subsidiaries, and their lenders have been engaged in discussions to restructure PG&E NEG's and its subsidiaries' debt obligations and other commitments since October 2002. No agreement has been reached yet and there can be no assurance that an agreement will be reached. Any restructuring agreement that may be reached would be implemented through a reorganization proceeding under Chapter 11 of the Bankruptcy Code. Although PG&E NEG and its subsidiaries are continuing their efforts to maximize cash and reduce liabilities, such efforts are not expected to restore the financial condition of PG&E NEG and its subsidiaries. Absent a negotiated agreement, the lenders may exercise their default remedies or forceJuly 8, 2003, PG&E NEG and certain of its subsidiaries ~~into an involuntary proceeding~~filed voluntary petitions for relief under the provisions of Chapter 11 of the Bankruptcy ~~Code. Notwithstanding~~Code in the ~~status~~U.S. Bankruptcy Court for the District of ~~current negotiations,~~Maryland, Greenbelt Division (referred to as the "Bankruptcy Court" in this report's discussion of PG&E NEG's Chapter 11 filing). Pursuant to Chapter 11, PG&E NEG a nd those subsidiaries retain control of their assets and ~~certain~~are authorized to operate their businesses as debtors-in-possession while they are subject to the jurisdiction of ~~its subsidiaries also may elect to voluntarily seek protection under~~ the Bankruptcy ~~Codeas early as~~Court. On July 8, 2003, PG&E NEG also filed a proposed plan of reorganization with the ~~second quarter~~Bankruptcy Court that, if implemented, would eliminate PG&E Corporation's equity interest in PG&E NEG.

As a result of ~~2003. Although~~PG&E NEG's Chapter 11 filing and the resignation of PG&E Corporation's representatives who previously served on the PG&E NEG Board of Directors and their replacement with Board members who are not affiliated with PG&E Corporation, ~~continues to provide assistance to~~ PG&E ~~NEG, its subsidiaries and its lenders in their negotiations, management does not expect~~Corporation no longer retains significant influence over the ~~outcome of any bankruptcy proceeding involving PG&E NEG or any of its subsidiaries to have a material adverse effect on the financial condition~~ongoing operations of PG&E ~~Corporation or the Utility.~~NEG.

This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and the Utility. Therefore, the Notes to the unaudited condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, PG&E NEG, and other ~~wholly-owned~~wholly owned and controlled subsidiaries. The Utility's Consolidated Financial Statements include its accounts and those of its ~~wholly-owned~~wholly owned and controlled subsidiaries. Both PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets as of December 31, 2002, were derived from the audited Consolidated Balance Sheets, filed in the combined 2002 Annual Report on Form 10-K, as amended.

PG&E Corporation and the Utility believe that the accompanying Consolidated Financial Statements reflect all adjustments that are necessary to present a fair statement of the consolidated financial position and results of operations for the interim periods. All material adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q. All significant intercompany transactions have been eliminated from the Consolidated Financial Statements.

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~~included in their combined 2002 Annual Report on Form 10-K, as amended, and PG&E Corporation's and the Utility's other reports filed with the Securities and Exchange Commission (SEC) since their combined 2002 Annual Report on Form 10-K, as amended, was filed.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) 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. As these estimates involve judgments on a wide range of factors, including future economic conditions that are difficult to predict, actual results could differ from these estimates.

PG&E Corporation's and the Utility's Consolidated Financial Statements have been prepared in accordance with the American Institute of Certified Public Accountants' Statement of Position (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~~PG&E NEG's Consolidated Financial Statements will be prepared in accordance with SOP 90-7 beginning in the third quarter of 2003. As a result of the Utility's ~~Chapter 11 filing~~ and PG&E NEG's ~~current liquidity concerns, such~~Chapter 11 filings, the realization of assets and liquidation of liabilities are subject to uncertainty. Under SOP 90-7, certain liabilities of the Utility existing prior to the Utility's Chapter 11 filing are classified as Liabilities Subject to Compromise on PG&E Corporation's and the Utility's Consolidated Balance Sheets. Additionally, professional fees and expenses directly ~~related~~rel ated to the Utility's Chapter 11 proceeding and interest income on funds accumulated during the ~~bankruptcy ar e~~Chapter 11 proceedings are reported separately as reorganization items. Finally, the extent to which the Utility's reported interest expense differs from its stated contractual interest is disclosed on the Utility's Consolidated Statements of ~~Operations.~~Income.

Certain amounts in the 2002 Consolidated Financial Statements have been reclassified to conform to the 2003 presentation. These reclassifications did not affect the consolidated net income reported by PG&E Corporation and the Utility for the periods presented.

PG&E Corporation incorporated the ~~clarified~~ disclosure requirements from Financial Accounting Standards Board (FASB) Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45), into its December 31, 2002, disclosures of guarantees. Beginning January 1, 2003, PG&E Corporation applied the initial recognition and ~~initial~~ measurement provisions of FIN 45 to guarantees issued or modified after December 31, 2002.

FIN 45 elaborates on existing disclosure requirements for most guarantees. It also clarifies that at the time a company issues a guarantee, it must recognize ~~an initial~~a liability for the fair value of the obligation it assumes under that guarantee, including its ongoing obligation to stand ready to perform over the term of the guarantee in the event that specified triggering events or conditions occur. This information also must be disclosed in interim and annual financial statements.

FIN 45 does not prescribe a specific account for the guarantor's offsetting entry when it recognizes the liability at the inception of the guarantee, noting that the offsetting entry would depend on the circumstances in which the guarantee was issued. There also is no prescribed approach included for subsequently measuring the guarantor's recognized liability over the term of the related guarantee. It is noted that the liability typically would be reduced by a credit to earnings as the guarantor is released from risk under the guarantee. The adoption of this interpretation did not have a material impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

On January 1, 2003, PG&E Corporation adopted ~~Statements~~Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible long-lived assets. SFAS No. 143 requires that an asset retirement obligation be recorded at fair value in the period in which it is incurred, if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with this Statement and costs recovered through the ratemaking process.

On January 1, 2003, PG&E Corporation adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal ~~Activities."~~Activities" (SFAS No. 146). This Statement supersedes previous accounting guidance, principally Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity" (EITF 94-3). SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF 94-3, a liability for an exit cost is recognized at the commitment date of an exit plan. SFAS No. 146 also establishes that the liability initially should be measured and recorded at fair value. The adoption of this Statement did not have any ~~current~~ impact on the Consolidated Financial Statements of PG&E Corporation or the ~~Utility.~~Utility at the date of adoption.

Change from Gross to Net Method of Reporting Revenues and Expenses ~~on Trading Activities~~

Effective atfor the quarter ended September 30, 2002, PG&E Corporation changed its method of reporting gains and losses associated with energy trading contracts from the gross method of presentation to the net method. PG&E Corporation believes that the net method provides a more accurate and consistent presentation of energy trading activities on the financial statements. Amounts to be presented under the net method include all gross margin elements related to energy trading activities.

Before implementation of the net method and the subsequent rescission of EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10), as noted below,Previously, PG&E Corporation had reported unrealized gains and losses on trading activities on a net basis in operating revenues. However, PG&E Corporation had reported realized gains and losses on a gross basis in operating income, as both operating revenues and costs of commodity sales and fuel. PG&E Corporation now is reporting realized gains and losses from trading activities on a net basis as operating revenues, and in accordance with the rescission of EITF 98-10, unrealized gains and losses on energy trading activities no longer are reported as these contracts are accounted for under the cost method.revenues.

Implementation of the net method has no net effect on gross margin, operating income, or net income. ~~Accordingly, PG&E Corporation continues to report realized income from non-trading activities on a gross basis in operating revenues and operating expenses.~~ Prior year financial statements have been reclassified to conform to the net method. This change reduced generation, transportation and trading revenues, and cost of commodity sales and fuel by $2,441 million for the three months ended June 30, 2002, and $4,057 million for the six months ended June 30, 2002.

~~The schedule below summarizes~~During the ~~amounts impacted~~second quarter of 2003, PG&E NEG determined that its historical financial reporting presentation of revenues and expenses related to its hedging and certain Independent System Operator (ISO) sales and purchase transactions had not been consistent. Certain types of transactions had been reported on a net basis (whereby revenues had been offset by the ~~change in methodology~~related expense item) and other types of transactions had been reported on a gross basis. In order to provide a consistent reporting of its trading and hedging transactions, PG&E ~~Corporation's Consolidated Statements~~Corporation has adopted a net presentation approach for such transactions. PG&E Corporation believes that this method of ~~Operations~~presentation is preferable in the circumstances. Adopting this change reduced previously reported revenues and expenses by $50 million for the three months ended March 31, ~~2002:~~

Prior Method of Presentation
(Gross Method)
- --------------------------------------
As Presented
(Net Method)
- ----------------------------

(in millions)
Three months ended
March 31, 2002
Three months ended
March 31, 2002

----------------------------
----------------------------
Energy commodities and services⁽¹⁾
$
2,114
$
498
Cost of commodities and services⁽²⁾
1,956
340

---------------
-------------
Net Subtotal
$
158
$
158

=========
========

In October 2002, the EITF rescinded EITF ~~98-10.~~Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10). Energy trading contracts that are derivatives in accordance with 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" (collectively, SFAS No. 133), will continue to be accounted for at fair value under SFAS No. 133. Contracts that previously were marked to market as trading activities under EITF 98-10 and that did not meet the definition of a derivative now are accounted for at cost, through a one-time adjustment recorded as a cumulative effect of a change in accounting principle. This requirement was effective as of January 1, 2003, and resulted in a $2$3 million loss, net of zero tax ~~reflected on the PG&E Corporation's Consolidated Statements~~benefits as a cumulative effect of ~~Operations for the three months ended March 31, 2003.~~accounting change. For PG&E Corporation, the majority of trading contracts are derivative ~~instruments~~instrum ents as defined in SFAS No. 133. The ~~r escission~~rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading purposes, which continue to be accounted for in accordance with SFAS No. 133. The reporting requirements associated with the rescission of EITF 98-10 were applied prospectively for all EITF 98-10 energy trading contracts entered into after October 25, 2002, although the number of energy trading contracts subject to the prospective implementation was considered immaterial.

Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per share is computed by dividing net income (loss), adjusted for ~~convertible note~~the net interest and amortization associated with PG&E Corporation's Convertible Subordinated Notes, by the sum of the weighted average number of common shares outstanding ~~plus~~and the assumed issuance of common shares for all 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:

The diluted earnings per share for the ~~three~~six months ended ~~March 31,~~June 30, 2003, excludes approximately ~~one~~1 million incremental shares related to employee stock options and shares held by grantor trusts, ~~five~~5 million incremental shares related to warrants, and 18 million incremental shares related to the 9.5 percent Convertible Subordinated Notes, and includes associated interest expense of $4$8 million (net of income taxes of $3$6 million) due to the anti-dilutive effect upon loss from continuing operations.

PG&E Corporation reflects the preferred dividends of subsidiaries as other expense for computation of both basic and diluted earnings per share.

PG&E Corporation and the Utility account for stock-based compensation using the intrinsic value method in accordance with the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," as allowed by SFAS No. 123, "Accounting for Stock-Based Compensation," (SFAS No. 123), as amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure, an Amendment of FASB Statement No. 123." Under the intrinsic value method, PG&E Corporation and the Utility do not recognize any compensation expense for stock options, as the exercise price is equal to the fair market value of a share of PG&E Corporation common stock at the time the options are granted. Had compensation expense been recognized using the fair value-based method under SFAS No. 123, PG&E Corporation's pro forma consolidated earnings (loss) and earnings (loss) per share would have been as follows:

Had compensation expense been recognized using the fair value-based method under SFAS No. 123, the Utility's pro forma consolidated earnings ~~(loss)~~ would have been as follows:

~~On January 2,~~As of June 30, 2003, ~~PG&E Corporation awarded~~a total of 1.6 million shares of restricted PG&E Corporation common stock had been awarded to eligible employees of PG&E Corporation and its subsidiaries. The shares were granted with restrictions and are subject to forfeiture unless certain conditions are met.

The restricted shares were issued at the grant date and are held in an escrow account. The shares become available to the employees as the restrictions lapse. In general, the restrictions on 80 percent of the shares lapse automatically over a period of four years at the rate of 20 percent per year. Restrictions to the remaining 20 percent of the shares will lapse at a rate of 5 percent per year if PG&E Corporation is in the top quartile of its comparator group as measured by annual total shareholder return for each year ending immediately before each annual lapse date.

Total compensation expense resulting from the restricted stock issuance reflected on PG&E Corporation's Consolidated Statements of Operations was $1.8 million for the ~~three months~~three-month and $3.2 million for the six-month periods ended ~~March 31,~~June 30, 2003, ~~was $1.4 million,~~ of which ~~$0.8~~$1.0 million for the three-month and $1.9 million for the six-month periods was recognized by the Utility.

PG&E Corporation's and the Utility's comprehensive income (loss) consists principally of changes in the market value of certain cash flow hedges under SFAS No. 133 ~~as amended.~~and the effects of the remeasurement of the defined benefit pension plan.

	PG&E Corporation				Utility				PG&E Corporation				Utility
	--------------------------				-------------------------
(in millions)	2003		2002		2003		2002		2003		2002		2003		2002
	----------		---------		---------		---------
Three months ended March 31
Three months ended June 30
Net income available for (loss allocated to) common stock	$	(354)	$	631	$	(79)	$	590	$	227	$	218	$	339	$	463
Net gain (loss) in other comprehensive income (OCI) from current period hedging transactions and price changes in accordance with SFAS No. 133	(1)		(75)		-		-
Net loss in other comprehensive income (OCI) from current period hedging transactions and price changes in accordance with SFAS No. 133									(4)		(9)		-		-
Net reclassification from OCI to earnings	5		5		-		-		10		-		-		-
Foreign currency translation adjustment	3		-		-		-		-		3		-		2
Retirement plan remeasurement (Note 8)										(60)		-		(60)		-
Other										-		1		-		-
	------------		------------		----------		----------
Comprehensive income (loss)	$	(347)	$	561	$	(79)	$	590	$	173	$	213	$	279	$	465
	=======		=======		======		======



Six months ended June 30
Net income (loss) available for (loss allocated to) common stock									$	(127)	$	849	$	260	$	1,053
Net loss in OCI from current period hedging transactions and price changes in accordance with SFAS No. 133									(5)		(84)		-		-
Net reclassification from OCI to earnings									15		5		-		-
Foreign currency translation adjustment									3		3		-		2
Retirement plan remeasurement (Note 8)										(60)		-		(60)		-
Other										-		1		-		-

Comprehensive income (loss)									$	(174)	$	774	$	200	$	1,055

The above changes to OCI are stated net of income taxes (benefits)of ~~$48~~$(37) million ~~at March 31,~~and $(46) million for the three- and six-month periods ended June 30, 2003, and ~~$38~~$(14) million ~~at March 31,~~and $24 million for the three- and six-month periods ended June 30, 2002.

In 2003, PG&E Corporation increased its valuation allowance due to the ~~continued~~ uncertainty in realizing certain state deferred tax assets arising at PG&E NEG. ~~During the first quarter of 2003, valuation~~Valuation allowances of ~~$10~~$7 million for the three-month and $17 million for the six-month periods ended June 30, 2003, were recorded in continuing operations. Additional valuation allowances of $7 million were recorded in discontinued operations, and $5 million in accumulated other comprehensive ~~loss.~~loss for the six-month period ended June 30, 2003.

In addition to the above reserves, PG&E NEG recorded valuation allowances due to ~~continued~~the uncertainty inof realizing federal deferred tax assets. These valuation allowances were determined on a stand-alone basis. ~~During the first quarter of 2003, valuation~~Valuation allowances of ~~$66~~$56 million for the three-month and $122 million for six-month periods ended June 30, 2003, were recorded in continuing operations. Additional valuation allowances (benefits) of ~~$37~~$(2) million and $35 million were recorded in discontinued operations, zero and $3 million recorded in cumulative effect of changes in accounting principles, and ~~$48~~$(4) million and $44 million recorded in accumulated other comprehensive ~~loss.~~loss for the three and six months ended June 30, 2003. These ~~reserves were~~PG&E NEG valuation allowances are eliminated in ~~consolidation, as PG&E Corporation believes that it is more likely than not that the federal deferred tax assets will be realized on a consolidated basis.~~consolidation.

In accordance with various agreements, the Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation. The Utility and PG&E Corporation exchange administrative and professional support services in support of operations. These services are priced either at the fully loaded cost (i.e., direct costs and allocation of overhead costs) or at the higher of fully loaded cost or fair market value, depending on the nature of the services provided. PG&E Corporation also allocates certain other corporate administrative and general costs to the Utility and other subsidiaries using a variety of factors, including the number of employees, operating expenses excluding fuel purchases, total assets, and other cost-causal methods. ~~Additionally,~~The Utility purchases transmission services from PG&E GTN. Effective April 1, 2003, the Utility no longer purchases gas commodity ~~and transmission services~~ from ~~and sells~~PG&E Energy Trading (PG&E ET). The Utility continues to sell reservation and ~~other~~othe r ancillary services to PG&E ~~NEG.~~ET. These services are priced at either tariff rates or fair market value ~~dependin g~~depending on the nature of the services provided. Intercompany transactions are eliminated in consolidation; therefore, no profit results from these transactions. The Utility's significant related party transactions and related receivable (payable) balances were as follows:

Payment of outstanding amounts owed as of July 8, 2003, the date of PG&E NEG's Chapter 11 filing, are subject to the approval of the Bankruptcy Court.

In June 2003, the FASB issued a new Derivatives Implementation Group (DIG) interpretation of SFAS No. 133, Issue No. C20, "Scope Exceptions: Interpretation of the Meaning ofNot Clearly and Closely Relatedin Paragraph 10(b) regarding Contracts with a Price Adjustment Feature" (DIG C20). DIG C20 specifies additional circumstances under which price adjustment features, such as those based on broad market indices, in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. Certain derivative contracts are exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and are not reflected on the balance sheet at fair value. One of the attributes necessary to qualify for the normal purchases and sales exception is that the pricing must be deemed to be clearly and closely related to the asset to be delivered under the contract. Under DIG C20, as long as the price adjustment feature in a contract is expected to be highly correlated to the asset to be delivered under that contract, the use of a broad market index (such as the consumer price index) as a price adjustment feature is considered clearly and closely related. Previously, under DIG C11, "Interpretations of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exceptions," the use of a price adjustment based on a broad market index was not considered to be clearly and closely related to the asset to be delivered, and the contract was not eligible for the normal purchases and sales exception. The guidance in DIG C11 is superseded by DIG C20.

The assessment of whether the contract qualifies for the normal purchase and sales exception, including whether the price adjustment is clearly and closely related to the asset being transacted, must be performed at the inception of the contract.

The implementation guidance in DIG C20 is effective for all existing and all future derivative contracts in the quarter beginning after July 10, 2003 (fourth quarter of 2003). Early application in the third quarter of 2003 is permitted. Application of the DIG C20 guidance to existing contracts that were not previously eligible for the normal purchases and sales exception under DIG C11 will be applied prospectively. The contract's fair value as of the date of adoption of DIG C20 should become the carrying value at that date. PG&E Corporation and the Utility currently are evaluating the impacts, if any, of DIG C20 on their Consolidated Financial Statements.

Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity

In May 2003, the FASB issued Statement No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). The Statement addresses concerns of how to measure and classify in the statement of financial position certain financial instruments that have characteristics of both liabilities and equity. The following freestanding financial instruments must be classified as liabilities: mandatorily redeemable financial instruments, obligations to repurchase an issuer's equity shares by transferring assets, and certain obligations to issue a variable number of shares.

The requirements of SFAS No. 150 are applicable to PG&E Corporation in the third quarter of 2003. The Statement will be implemented by reclassifying and remeasuring the Utility's $137 million of preferred stock with mandatory redemption provisions as a liability, at the present value of the redemption amount using the rate implicit in the contract at inception, without reclassifying prior dividends or accruals. The remeasurement and reclassification will not have an impact on earnings of PG&E Corporation or the Utility. The preferred stock with mandatory redemption provisions are to be measured subsequently at the amount of cash that would be paid under the conditions specified in the contract if settlement occurred at the reporting date. All amounts paid or to be paid to the holders of the financial instruments in excess of the initial measured amount are reflected in interest cost.

In May 2003, the EITF reached consensus on EITF 01-8, "Determining whether an Arrangement Contains a Lease" (EITF 01-8). EITF 01-8 establishes criteria to be applied to any new or modified agreement in order to ascertain if such agreement is in effect a lease, and subject to lease accounting treatment and disclosure requirements principally found in SFAS No. 13, "Accounting for Leases" (SFAS No. 13). EITF 01-8 is effective for all new or modified arrangements entered into as of July 1, 2003. PG&E Corporation and the Utility currently are assessing the impact of EITF 01-8.

In April 2003, the FASB issued Statement No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS No. 149). SFAS No. 149 amends and clarifies the accounting and reporting for derivative instruments, including certain derivatives embedded in other contracts, and for hedging activities under SFAS No. 133. ~~The amendments in~~ SFAS No. 149 ~~require that contracts with comparable characteristics be accounted for similarly. The Statement~~ clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative according to SFAS No. 133 and when a derivative contains a financing component that warrants special reporting in the statement of cash flows. In addition, the Statement amends the definition of an underlying to conform it to language used in FIN No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others", and amends certain other existing pronouncement s. The provisions of ~~the Statement~~SFAS No. 149 that relate to SFAS No. 133 Implementation Issues that have been effective for periods that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates.

The requirements of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. PG&E Corporation isand the Utility are currently evaluating the impacts, if any, of SFAS No. 149 on its Consolidated Financial Statements.

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46), which expands upon existing accounting guidance addressing when a company should include in its financial statements the assets, liabilities, and activities of another entity or arrangement with which it is ~~involved with~~. ~~FIN 46 notes that many of what are now referred to as~~involved. A "variable interest ~~entities"~~entity" is an entity that does not have ~~commonly been referred~~sufficient equity investment at risk to ~~as special-purpose entities~~permit the entity to finance its activities without additional subordinated financial support from other parties or ~~off-balance sheet structures. However,~~an entity where equity investors lack the ~~Interpretation's guidance is to be applied to not only these entities but to all entities and arrangements found within a company. FIN 46 provides some general guidance as to the definition~~essential characteristics of a ~~variable interest entity. PG&E Corporation is currently evaluating all entities and arrangements it is involved with to determine if they meet the FIN 46 criteria as variable interest entities.~~controlling financial interest.

Until the issuance of FIN 46, a company generally included another entity in its ~~Consolidated Financial Statements~~consolidated financial statements only if it controlled the entity through voting interests. FIN 46 changes that by requiring a variable interest entity to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity's activities or entitled to receive a majority of the entity's residual returns, or both. A company that consolidates a variable interest entity is now referred to as the "primary beneficiary" of that entity.

FIN 46 requires disclosure of variable interest entities that the company is not required to consolidate but in which it has a significant variable interest.

The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. There were no new variable interest entities created by PG&E Corporation between February 1, 2003, and ~~March 31,~~June 30, 2003. The consolidation requirements ~~apply to variable interest entities created before January 31, 2003, in the first fiscal year or interim period beginning after June 15, 2003, so these requirements would be~~are applicable to PG&E Corporation in the third quarter of 2003. Certain new and expanded disclosure requirements must be applied to PG&E Corporation's March 31, 2003 disclosures if there is an assessment that it is reasonably possible that an enterprise will consolidate or disclose information about a variable interest entity when FIN 46 becomes effective. PG&E Corporation ~~is currently~~and the Utility are evaluating the impacts of FIN 46's initial recognition, measurement, and disclosure provisions on ~~its~~the Consolidated Financial ~~Statements.~~Statements, and currently are unable to estimate variable interest entities that will be consolidated or disclosed when FIN 46 becomes effective.

In 1998, California implemented electric industry restructuring and established a market framework for electric generation in which generators and other electricity providers were permitted to charge market-based prices for electricity sold on the wholesale market. The restructuring of the electric industry was mandated by the California Legislature in Assembly Bill (AB) 1890. The mandate included a retail electricity rate freeze and a plan for recovery of generation-related costs that were expected to be uneconomic under the new market framework (transition costs). Additionally, the CPUC strongly encouraged the Utility to sell more than 50 percent of its fossil fuel-fired generation facilities and made it economically unattractive for the Utility to retain its remaining generation facilities. The new market framework called for the creation of the Power Exchange (PX) and the Independent System Operator (ISO). Before it ceased operation in January 2001, the PX established m arket-clearing prices for electricity. The ISO's role is 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 generation to, and purchase all electricity for its retail customers from, the PX. Customers were given the choice of continuing to buy electricity from the Utility, or to buy electricity from independent power generators or retail electricity suppliers (customers who chose to buy from independent power generators or retail electricity suppliers are referred to as direct access customers). Mostdiscussion of the Utility's ~~customers continued~~Chapter 11 filing matters below should be read in conjunction with Note 2 of the Notes to ~~buy electricity from~~ the ~~Utility.~~Consolidated Financial Statements of PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended.

For the seven-month period from June 2000 through December 2000, wholesale electric prices in California averaged $0.18 per kilowatt-hour (kWh). During this period, the Utility's retail electric rates were frozen and provided only approximately $0.05 per kWh to pay for the Utility's electricity costs.

~~The frozen rates were designed to allow~~On April 6, 2001, the Utility to recover its authorized costs and, to the extent the frozen rates generated revenues in excess of the Utility's authorized costs, recover its transition costs. During the California energy crisis, frozen rates were insufficient to cover the Utility's electricity procurement and other costs. Since the Utility no longer could conclude that its under-collected purchased power and remaining transition costs were probable of recovery, the Utility charged $6.9 billion to expense for these costs at December 31, 2000. The Utility's inability to recover procurement costs from customers ultimately resulted in billions of dollars in defaulted debt and unpaid bills, and caused the Utility to filefiled a voluntary petition for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court ~~on April 6, 2001.~~

In January 2001, the CPUC increased electric rates by $0.01 per kWh, and in March 2001 by another $0.03 per kWh, and restricted use of these surcharge revenues to "ongoing procurement costs" and "future power purchases."

In May 2001, the CPUC authorized the Utility to collect an additional $0.005 per kWh in revenues for 12 months to make up for the time lag between March 2001, when the CPUC authorized the $0.03 surcharge, and June 2001, when the Utility began collecting the $0.03 surcharge. Although the collection of this "half-cent" surcharge originally was scheduled to end on May 31, 2002, the CPUC issued a resolution ordering the Utility to continue collecting the half-cent surcharge until further consideration by the CPUC and to record the surcharge revenues in a balancing account.

In November 2002, the CPUC approved a decision modifying the restrictions on the use of revenues generated by the surcharges to permit the revenues to be used for the purpose of securing or restoring the Utility's reasonable financial health, as determined by the CPUC. The CPUC will determine in other proceedings how the surcharge revenues can be used, whether there is any cost or other basis to support specific surcharge levels, and whether the resulting rates are just and reasonable. After the CPUC determines when the AB 1890 rate freeze ended, the CPUC will determine the extent and disposition of the Utility's under-collected costs, if any, remaining at the end of the rate freeze. If the CPUC determines that the Utility recovered revenues in excess of its transition costs or in excess of other permitted uses, the CPUC may require the Utility to refund such excess revenues.

~~In December 2002, the CPUC issued a decision authorizing the Utility to record amounts related to the $0.01 and $0.03 surcharge revenues as an offset to unrecovered transition costs.~~

Based on the November and December 2002 CPUC decisions discussed above and an agreement between the CPUC and another California investor-owned utility, Southern California Edison (SCE), in which SCE was allowed to use its half-cent surcharge to offset its California Department of Water Resources (DWR) revenue requirement, the Utility believes it can continue to recognize revenues related to the $0.01, $0.03, and half-cent surcharges after the statutory end of the rate freeze, which was March 31, 2002. As such, the Utility has not recorded a regulatory liability for these surcharge revenues, or any portion thereof, in its financial statements. If the CPUC requires the Utility to refund any of these revenues in the future, the Utility's earnings could be materially affected.

During 2001, the price of wholesale electricity stabilized. In 2001 and 2002, as a result of the wholesale electricity price stabilization and the CPUC-authorized surcharges, the Utility's total generation-related electric revenues were greater than its generation-related costs, resulting in the partial recovery of previously written-off under-collected purchased power and transition costs. As of December 31, 2000, the Utility had accumulated a total of approximately $4.1 billion (after-tax) in unrecovered purchased power and generation-related transition costs. This amount was charged to earnings at that time because the Utility could no longer conclude that such costs were probable of collection through regulated rates. Generation-related costs in excess of generation-related revenues continue to be expensed as they are incurred. As of March 31, 2003, the outstanding balance of the Utility's unrecovered purchased power and transition costs amounted to $2.4 billion (after-tax) compared to a balance of $2.2 billion (after-tax) at December 31, 2002. The increase in the unrecovered balance from December 31, 2002, to March 31, 2003, was due to first quarter 2003 generation-related costs in excess of generation-related revenues. Typically, electric revenues are lower in the winter because of lower consumption and lower winter rates.

The recovery of these remaining under-collected purchased power costs and transition costs will depend on a number of factors, including the ultimate outcome of the Utility's bankruptcy and future regulatory and judicial proceedings, including the outcome of the Utility's filed rate doctrine litigation. (The filed rate doctrine litigation refers to a lawsuit filed in November 2000 in the U.S. District Court for the Northern District of ~~California by~~California. Pursuant to Chapter 11, the Utility against the CPUC Commissioners, asking the court to declare that the federally approved wholesale electricity costs that the Utility has incurred to serve its customers are recoverable in retail rates under the federal filed rate doctrine.)

~~Under AB 1890, the rate freeze was scheduled to end on the earlier of March 31, 2002, or the date that the Utility recovered all~~retains control of its generation-related transition costs as determined by the CPUC. However, in January 2002, the CPUC issued a decision finding that new California legislation, AB 6X, had materially affected the implementation of AB 1890. The CPUC scheduled further proceedings to address the impact of AB 6X on the AB 1890 rate freeze for the Utility and to determine the extent and disposition of the Utility's remaining unrecovered transition costs. In its November 2002 decision regarding the surcharge revenues discussed above, the CPUC reiterated that it had yet to decide when the rate freeze ended and the disposition of any under-collected costs remaining at the end of the rate freeze.

~~During the third quarter of 2002, and again during the first quarter of 2003, the CPUC represented that, since utilities now are required under state law (AB 6X) to retain their generating~~ assets and ~~the CPUC has regained~~is authorized to operate its traditional rate authority over those assets, costs associated with those assets may be recovered by the utilities in the traditional way under cost-based regulation. Based on these CPUC decisions and representations, the Utility believes it can continue to record revenues collected under its existing overall retail rates, subsequent to the statutory end of the rate freeze.

However, the CPUC's proceedings to consider the impact of AB 6X on the AB 1890 rate freeze and the disposition of the Utility's unrecovered transition costs are still pending. The California Supreme Court currently is considering the authority of the CPUC to enter into a settlement with SCE, which allows SCE to recover under-collected procurement and transition costs in light of the provisions of AB 1890. Oral argument has been set before the California Supreme Court in this case on May 27, 2003. Either in response to judicial decisions such as this one, or on its own initiative, it is possible that at some future date the CPUC may change its interpretation of law or otherwise seek to change the Utility's overall retail electric rates retroactively. The Utility has not provided reserves for potential refunds of any of these revenues as of March 31, 2003. If the CPUC requires the Utility to refund any of these revenues in the future, the Utility's earnings could be materially affected.

In January 2001, as wholesale electric prices continued to exceed retail rates, the major credit rating agencies lowered their ratings for the Utility and PG&E Corporation to non-investment grade levels. Consequently, the Utility lost access to its bank facilities and capital markets, and no longer could continue buying electricity to deliver to its customers. As a result, in the first quarter of 2001, the California Legislature and the Governor of California authorized the DWR to purchase electricity for the Utility's customers and to issue revenue bonds to finance electricity purchases (governed by AB 1X). Initially, the DWR indicated that it intended to buy electricity only at "reasonable prices" to meet the Utility's net open position, leaving the ISO to purchase the remainder in order to avoid blackouts. The Utility accrued approximately $1 billion for ISO billings for the period January 17, 2001, through April 6, 2001. However, in 2001 and 2002, the FERC issued a series of orders directing the ISO to buy electricity only on behalf of creditworthy entities. The Utility currently actsbusiness as a billing and collection agent for electricity provided to its customers by the DWR. As such, revenues associated with these activities are passed through to the DWR and are not included in the Utility's results of operations.

In February 2002, the CPUC approved a decision, which was further modified in March 2002, that set the statewide DWR revenue requirement for 2001 and 2002. The DWR revenue requirement decision allows the DWR to collect amounts from ratepayers to provide the revenues needed by the DWR to procure electricity for the customers of the Utility and the other California investor-owned utilities (IOUs).

The DWR's revenue requirement included the procurement charges previously billed by the ISO and accrued by the Utility. As such, because of certain 2001 and 2002 FERC orders and the February and March 2002 CPUC decisions, in the first quarter of 2002 the Utility reversed the excess of the ISO accrual (for the period from January 17, 2001, through April 6, 2001) over the amount of the additional DWR revenue requirement applicable to 2001, for a net reduction of accrued purchased power costs of approximately $595 million (pre-tax).

In October 2002, the DWR filed a proposed amendment to the CPUC's May 16, 2002, servicing order requesting both prospective and retrospective changes to the calculation that determines the amount of revenue the Utility is required to pass through to the DWR. Under its statutory authority, the DWR may request the CPUC to order utilities to implement such amendments, and the CPUC has approved such amendments in the past without significant change. In December 2002, the CPUC issued an operating order requiring the Utility to perform the operational, dispatch, and administrative functions for the DWR's allocated contracts beginning on January 1, 2003. The operating order, which applies prospectively, includes the DWR's proposed method of calculating the amount of revenues that the Utility must pass through to the DWR but does not change the servicing order relating to the same calculation. In March 2003, the DWR submitted a letter to the CPUC reaffirming its position and quantifying th e amount of revenues that the DWR has requested the CPUC to order the Utility to pass through to the DWR. As a result, the Utility has accrued an additional $96 million (pre-tax) liability for pass-through revenues for electricity previously provided by the DWR to the Utility's customers. In total as of March 31, 2003, the Utility has accrued an additional $539 million (pre-tax) liability for pass-through revenues to the DWR based on the DWR's October 2002 proposed amendment, the CPUC's December 2002 operating order, and the March 2003 letter from the DWR. Of this amount, $369 million (pre-tax) had been accrued at December 31, 2002.

In April 2003, the Utility and the DWR entered into an operating agreement, which has been approved by the CPUC. Effective in April 2003, the operating agreement supersedes the operating order. The operating agreement provides that the Utility will begin passing through revenues to the DWR consistent with the DWR's October 2002 and March 2003 requests for amendments to the servicing order, but subject to the outcome of the CPUC's consideration of the DWR's requests. In addition, if the CPUC grants the DWR's request for changes to the servicing order, the Utility would be required to make additional cash payments to the DWR consistent with its accrual of pass-through revenues to the DWR for the periods prior to the effective date of the operating agreement.

In October 2002, the Utility filed a lawsuit in a California court asking the court to find that the DWR's revenue requirements had not been demonstrated to be "just and reasonable" (as required by AB 1X) and lawful. The Utility asked the court to order the DWR's revenue requirement determination to be withdrawn as invalid, and that the DWR be precluded from imposing its revenue requirements on the Utility and its customers until it has complied with the law. The lawsuit is scheduled to be considered by the court during the third or fourth quarter of 2003.

Under AB 1X, the DWR is prohibited from entering into new agreements to purchase electricity to meet the net open position of the IOUs after December 31, 2002. In September 2002, the Governor signed California Senate Bill (SB) 1976 into law. As required by SB 1976, each California IOU submitted an electricity procurement plan to meet the residual net open position associated with that utility's customer demand.

A central feature of the SB 1976 regulatory framework is its direction to the CPUC to create new electric procurement balancing accounts to track and allow recovery of the differences between recorded revenues and costs incurred under an approved procurement plan. The CPUC must review the revenues and costs associated with the Utility's electric procurement plan at least semi-annually and adjust rates or order refunds, as appropriate, to properly amortize the balancing accounts. The CPUC must establish a schedule for amortizing the over-collections or under-collections in the electric procurement balancing accounts so that the aggregate over-collections or under-collections reflected in the accounts do not exceed 5 percent of the IOUs' actual recorded generation revenues for the prior calendar year, excluding revenues collected on behalf of the DWR. Mandatory semi-annual review and adjustment of the balancing accounts will continue until January 1, 2006, after which time the CPUC will conduct electric procurement balancing account reviews and adjust retail ratemaking amortization schedules for the balancing accounts as the CPUC deems appropriate and in a manner consistent with the requirements of SB 1976 for timely recovery of electricity procurement costs. Additionally, in a December 2002 interim opinion, the CPUC established a maximum annual procurement disallowance for administration of all contracts and least-cost dispatch of resources equal to twice the Utility's annual administrative costs of managing procurement activities, including the administration and dispatch of electricity associated with DWR allocated contracts.

In December 2002, the CPUC issued an interim opinion adopting the Utility's electricity procurement plan for 2003. On January 1, 2003, the Utility resumed the function of procuring electricity to meet the portion of its customers' needs that is not covered by the combination of the allocation of electricity from existing DWR contracts and the Utility's own electric resources and contracts. To meet this requirement, the Utility entered into contracts for fuel supply, capacity, and transmission rights that limit exposure to potentially high congestion charges. These one-year term contracts did not have a material impact on the Utility's commitments previously disclosed in its 2002 Annual Report on Form 10-K, as amended.

The Utility filed its long-term procurement plan (long-term plan), which covers the next 20 years, with the CPUC on April 15, 2003. The Utility's long-term plan states that certain important policy issues, including the restoration of the Utility's financial health and investment grade credit rating, should be resolved before the CPUC can adopt a credible long-term plan for the Utility. The long-term plan indicates that a fundamental requirement for restoring the Utility's credit rating is the provision of procurement cost recovery by the CPUC. The Utility also mentions other conditions that the CPUC should consider implementing before adopting its long-term plan, including providing comprehensive guidelines that give the Utility the flexibility to react quickly to changing market conditions and determining which customers the Utility will serve and under what price. In this latter condition, the Utility notes that it will continue to be exposed to unrecovered costs unless the CPUC requires customer c lasses to pay the full amount of costs incurred on their behalf. While the long-term plan states that there is no immediate need for the Utility to construct or make long-term commitments to new resources, it notes that the Utility's role in future generation development will be directly impacted by its credit rating.

Since 2001, the Utility and the other California IOUs have acted as the billing and collection agents for the DWR's sales of its electricity to retail customers. In September 2002, the CPUC issued a decision allocating the electricity provided under existing DWR contracts to the customers of the IOUs. This decision required the Utility, along with the other IOUs, to begin performing all the day-to-day scheduling, dispatch, and administrative functions associated with the DWR contracts allocated to the IOUs' respective portfolios by January 1, 2003.

Although the DWR retains legal and financial responsibility for these contracts, the DWR has stated publicly that it intends to transfer full legal title of, and responsibility for, the DWR electricity contracts to the IOUs as soon as possible. However, SB 1976 does not contemplate a transfer of title of the DWR contracts to the IOUs. In addition, the operating agreement approved by the CPUC in April 2003 (implementing the Utility's operational and scheduling responsibility with respect to the DWR allocated contracts) specifies that the DWR will retain legal and financial responsibility for the contracts. The Utility's proposed plan of reorganization prohibits the Utility from accepting, directly or indirectly, assignment of legal or financial responsibility for the DWR contracts. Either the State of California (State) or the CPUC may seek to provide the DWR with authority to effect such a transfer of legal title in the future. The Utility has informed the CPUC, the DWR, and the State that the U tility would vigorously oppose any attempt to transfer the DWR allocated contracts to the Utility without the Utility's consent.

~~On April 6, 2001, the Utility filed for relief under Chapter 11 of the Bankruptcy Code, causing the Utility to become~~debtor-in-possession while subject to the jurisdiction of the Bankruptcy Court. ~~Throughout the Chapter 11 proceeding, the Utility has maintained control over its assets~~PG&E Corporation and ~~has been authorized to operate its business as a debtor-in-possession. Subsidiaries~~subsidiaries of the Utility, including PG&E Funding, LLC (which holds rate reduction bonds) and PG&E Holdings, LLC (which holds stock of the Utility), are not included in the Utility's Chapter 11 filing. PG&E Corporation, the Utility's parent, and PG&E NEG have not filed for Chapter 11 and are not included in the Utility's Chapter 11 filing. PG&E Corporation, however, is a co-proponent of the Utility's proposed plan of reorganization (Plan) described below.

In connection with the Utility's Chapter 11 ~~filing,~~proceeding, various parties filed claims with the Bankruptcy Court totaling approximately $50.1 ~~billion through March 31, 2003.~~billion. Of these claims, approximately ~~$26.5~~$27.0 billion have been disallowed ~~or withdrawn. Of~~by the ~~remaining $23.6 billion of filed claims, pursuant~~Bankruptcy Court due to ~~the Plan~~objections, claim withdrawals, and alternative plan (discussed below), claims asserted in the amount of approximately $5.5 billion are expected to pass through the bankruptcy proceeding and be determined in the appropriate court or other tribunal during the bankruptcy proceeding or after it concludes.

agreements with claimants. The Utility has objected to, ~~approximately $1 billion of the remaining $23.6 billion of filed claims. These objections are pending in the Bankruptcy Court.The Utility~~or intends to object to, approximately ~~$4.4~~$5.0 billion of the remaining ~~$23.6~~$23.1 billion of filed claims. These objections relate primarily to the ISO, California Power Exchange (PX), and generator claims. Generator claims could be reduced significantly based on the FERC's March 26, 2003, decision finding that electricity suppliers ~~significantly~~ overcharged California buyers, including ~~IOUs,~~California investor-owned utilities (IOUs), from October 2, 2000, to June 20, 2001. In addition, the Utility is in settlement discussions with certain claimants. These settlement discussions could further reduce outstanding claims. Finally, of the remaining $23.1 billion of filed claims, approximately $5.4 billion are expected to pass through the Chapter 11 proceeding and be determined in the appropriate court or other tribunal during or after the Chapter 11 proceeding.

The Utility has recorded its estimate of all valid claims at ~~March 31,~~June 30, 2003, as ~~$9.4~~$9.5 billion of Liabilities Subject to Compromise and $3.0 billion of Long-Term Debt. ~~The Utility has paid certain claims authorized by the Bankruptcy Court, as discussed below, and reduced the amount~~As of ~~outstanding claims accordingly. In addition, since its Chapter 11 filing,~~December 31, 2002, the Utility ~~has accrued intere st on all claims it considers valid. This additional interest accrual is not included in the original $50.1~~had recorded $9.4 billion of ~~claims filed.~~

~~In addition~~Liabilities Subject to ~~other parties,~~Compromise. The increase from $9.4 billion is primarily due to interest accruals during the City of Palo Alto and the Northern California Power Agency (NCPA) filed an objection to the Plan and the CPUC's alternative proposed plan of reorganization. The objection asserts that, by virtue of the Utility's termination of a wholesale electric transmission contract between the NCPA and the Utility, NCPA members, including Palo Alto, will now be required to obtain transmission service through the California ISO and will be subject to substantial ISO charges. Palo Alto and the NCPA further assert that the Utility's motivation for terminating the NCPA transmission contract was anticompetitive and violated federal antitrust laws. They claim that damages associated with these increased ISO congestion charges could exceed $1 billion (which Palo Alto and the NCPA have indicated they would seek to treble under federal antitrust law). In January 2003, the Bankruptcy Court held an estimation hearing to determine what value to put on a possible future damages award that Palo Alto and the NCPA might receive, should they file, pursue, and establish liability on their antitrust claim. The Utility believes that Palo Alto's and the NCPA's claims are without merit.

The Bankruptcy Court has authorized certain payments and actions necessary for the Utility to continue its normal business operations while operating as a debtor-in-possession. For example, the Utility is authorized to pay employee wages and benefits, amounts ~~payable to certain qualified~~due under contracts with the majority of qualifying facilities (QFs), interest on certain secured and unsecured debt, environmental remediation expenses, and expenditures related to property, plant and equipment. In addition, the Utility is authorized to refund certain customer deposits, use certain bank accounts and make cash collateral deposits, and assume responsibility for various hydroelectric contracts. The Utility also has received permission from the Bankruptcy Court to make payments on (1) pre- and post-petition interest on certain claims, (2) pre-petition ~~trade payables to the majority of QFs and to certain other vendors, and (3) pre-petition~~ secured debt that has ~~matured.~~matured, and (3) certain other vendors.

~~As specified in the Plan described below, the~~The Utility has agreed to pay pre- and post-petition interest on Liabilities Subject to Compromise at the rates set forth ~~below, plus additional interest on certain claims as discussed~~ below.

~~Since~~As the ~~Plan~~Utility's proposed plan of reorganization (see below) did not become effective on or before February 15, 2003, the interest rates for Commercial Paper Claims, Floating Rate Notes, Senior Notes, Medium-Term Notes, and Revolving Line of Credit Claims ~~have been increased by~~set forth above reflect an increase of 37.5 basis points ~~above~~over the originally agreed upon rates, ~~presented above,~~ for periods on and after February 15, 2003. IfSince the ~~Plan does~~plan of reorganization will not become effective on or before September 15, 2003, the interest rates for these claims on and after such date will be increased by an additional 37.5 basis points. Finally, if the effective date does not occur on or before March 15, 2004, the interest rates for these claims on and after such date will be increased by an additional 37.5 basis points. For other claims, the Utility has recorded interest at the contractual or FERC-tariffed interest rate. When those rates do not apply, the Utility has recorded interest at the federal judgment rate.

~~The Utility and~~In September 2001, PG&E Corporation ~~jointly have~~and the Utility submitted a proposed a plan of reorganization ~~referred~~ to as the ~~Plan, which would allow~~Bankruptcy Court (the original plan of reorganization) that proposed to disaggregate the ~~Utility~~Utility's current business and to ~~restructure its businesses and~~ refinance the restructured businesses. ~~The Plan is designed to align~~In April 2002, the CPUC, later joined by the Official Committee of Unsecured Creditors (OCC), submitted a competing proposed plan of reorganization with the Bankruptcy Court that did not provide for disaggregation of the Utility's ~~existing~~business. In March 2003, the Bankruptcy Court stayed all proceedings relating to the confirmation trial for the competing plans to allow the Utility, the CPUC, and certain other parties to participate in a judicially supervised settlement conference in order to explore the possibility of resolving the differences between the competing plans of reorganization.

On June 19, 2003, PG&E Corporation, the Utility, and the staff of the CPUC announced a proposed settlement agreement that contemplates a new plan of reorganization (Settlement Plan) to supersede the competing plans of reorganization. Under the proposed settlement agreement, PG&E Corporation and the Utility would agree that they no longer would propose to disaggregate the historic businesses of the Utility as had been proposed in their original plan of reorganization. Instead, the Utility would remain a vertically integrated utility subject to the CPUC's jurisdiction.

The treatment of creditors under the ~~regulators~~Settlement Plan would be consistent with that ~~best match~~provided in the ~~business functions. Retail assets (natural gas and electricity distribution) would remain~~Utility's original plan of reorganization, except that those creditors that were to receive long-term notes to be issued by the limited liability companies contemplated under the ~~retail regulator,~~original plan of reorganization or a combination of cash and long-term notes would be paid entirely in cash. The Settlement Plan contemplates satisfaction of allowed claims in the Utility's Chapter 11 proceeding in cash from the issuance of approximately $8.7 billion in debt (which may be either secured or unsecured depending on market conditions at the time of issuance), cash on hand, or, in some cases, the reinstatement of the underlying debt. The actual amount of debt that the Utility would issue will depend upon how certain claims are resolved and the amount of cash on hand at the time the Settlement Plan becomes effective, as well as cash requirements related to closing out any interest rate hedges and whether all intended re instated debt will be reinstated.

The proposed settlement agreement is subject to the approval of the Boards of Directors of PG&E Corporation and the Utility, as well as the CPUC. In addition, the proposed settlement agreement must be executed by all parties on or before December 31, 2003. The ~~wholesale assets (electric transmission, interstate natural gas transportation, and electric generation) would be placed under wholesale regulators,~~CPUC will conduct evidentiary hearings during September 2003 before deciding whether or not to approve the ~~FERC~~proposed settlement agreement. On July 25, 2003, the Utility filed its testimony in support of the proposed settlement agreement. Testimony from the staff of the CPUC and the ~~Nuclear~~ OCC was also filed on July 25, 2003. The CPUC currently is expected to vote on the settlement agreement on December 18, 2003.

In addition, the Bankruptcy Court must confirm the Settlement Plan. While the CPUC is not a proponent, it would agree under the proposed settlement agreement to support the Settlement Plan. On July 31, 2003, the Bankruptcy Court approved the disclosure statement that will be used to solicit approval of the Settlement Plan from creditors entitled to vote on the Settlement Plan. On August 1, 2003, the Bankruptcy Court approved the solicitation procedures and ordered that the solicitation period to start on August 15 and end on September 29, 2003. The Bankruptcy Court has ordered that the confirmation hearing begin on November 3, 2003, and that all objections to the Settlement Plan be filed by September 2, 2003.

The proposed settlement agreement provides for a new regulatory asset (Regulatory Asset) to restore the ~~retail-focused business~~Utility to financial health and to maintain and improve the Utility's financial health in the future. The Regulatory Asset would be a ~~natural gas~~separate and ~~electricity distribution company (Reorganized Utility), representing approximately 70 percent of the book value~~additional part of the Utility's ~~current assets.~~

~~In contemplation~~rate base of ~~the Plan becoming effective, the Utility has created three new limited liability companies, the LLCs, which currently are owned by~~approximately $3.7 billion, pre-tax, included in non-current assets on the Utility's ~~wholly-owned subsidiary, Newco Energy Corporation (Newco). On the effective date of the Plan, the~~balance sheet. The Regulatory Asset would be amortized on a mortgage-style basis over nine years beginning January 1, 2004.

The Utility would ~~transfer substantially all~~continue to cooperate with the ~~assets~~CPUC and ~~liabilities primarily related~~the State of California in seeking refunds from power generators. The net after-tax amount of any refunds, claim offsets, or other credits from generators or other energy suppliers relating to the Utility's ~~electricity generation business~~power procurement costs that the Utility actually realizes in cash or by offset of creditor claims in its Chapter 11 proceeding would be applied to ~~Electric Generation LLC (Gen),~~reduce the ~~assets and liabilities primarily related to the Utility's electricity transmission business to ETrans LLC (ETrans),~~outstanding balance and the ~~assets~~remaining amortization of the Regulatory Asset. Amounts received in cash by the Utility for electric claims under the master settlement agreement with El Paso Corporation and ~~liabilities primarily related to the Utility's natural gas transportation and storage business to GTrans LLC (GTrans).~~

The ~~Plan proposes that~~Regulatory Asset would earn a return on equity (ROE) of at least 11.22 percent for the ~~effective date~~life of the ~~Plan,~~Regulatory Asset. For 2004 and 2005, the ~~Utility would distribute to PG&E Corporation all of the outstanding~~ common stock of Newco. Each of ETrans, GTrans, and Gen would continue to be an indirect wholly-owned subsidiary of PG&E Corporation. Finally, on the effective date of the Plan or as promptly thereafter as practicable, PG&E Corporation would distribute all the sharesequity ratio of the Utility's capital structure would be the higher of forecast average equity ratio (in accordance with the 2003 cost of capital proceeding to be filed by the Utility for calendar year 2004 and the 2005 cost of capital proceeding, or such other CPUC proceedings as may be appropriate) or 48.60 percent. Once the common ~~stock that it then holds to~~equity ratio of the Utility's capital structure reaches 52.00 percent, the authorized common equity ratio of the Regulatory Asset would be no less than 52.00 percent for the remaining life of the Regulatory Asset. The CPUC would use its ~~existing shareholders~~usual method for tax-effecting the ROE component of the Regulatory Asset in ~~a spin-off transaction. After~~establishing the ~~spin-off,~~Utility's revenue requirements for the ~~Reorganized~~Regulatory Asset. The Utility would ~~be an independent publicly held company.~~ record this regulatory asset when events that meet applicable accounting rules occur.

The ~~common stock of~~CPUC would agree that the ~~Reorganized Utility generally~~Utility's rate base for the utility retained generation (URG) would be ~~freely tradable by~~deemed just and reasonable and would not be subject to modification, adjustment, or reduction, except as necessary to reflect capital expenditures and any change in authorized depreciation. This would result in the ~~recipients.~~recording of an additional regulatory asset of approximately $1.3 billion, pre-tax, for the future recovery of generation-related assets that were charged to expense in 2000. The ~~Reorganized Utility~~CPUC would ~~retain~~not be precluded from determining the ~~name "Pacific Gas and Electric Company," and apply to list its common stock on the New York Stock Exchange.~~

~~Although the Reorganized Utility would be legally separated from the LLCs, the Reorganized Utility would have significant operating relationships with the LLCs covering a range~~reasonableness of ~~functions and services~~any capital expenditures made for URG after the effective date of the ~~Plan.~~

~~During 2002, the Utility undertook several initiatives to prepare for separation under the~~Settlement Plan. The Utility ~~has spent approximately $43 million~~would record this regulatory asset when events that meet applicable accounting rules occur.

The CPUC would not reduce or impair the value of the Regulatory Asset or the Utility's rate base for its URG, by taking the Regulatory Asset or the Utility's rate base for its URG, or their amortization or earnings into account when setting other Utility revenue requirements and resulting rates. The CPUC also would not take the settlement agreement or the Regulatory Asset into account in ~~2002~~establishing the Utility's authorized ROE or capital structure.

California Department of Water Resources Contracts - The ~~Plan proposes~~Utility would agree to ~~satisfy allowed claims with cash, long-term notes issued by~~accept an assignment of or to assume legal and financial responsibility for the LLCs, or a combination of cash and such notes. Each of ETrans, GTrans, and Gen would issue long-term notes to the Reorganized Utility and the Reorganized Utility then would transfer the notes to certain holders of allowed claims. In addition, each of the Reorganized Utility, ETrans, GTrans, and Gen would issue "new money" notes in registered public offerings. These notes would be secured if necessary to obtain investment-grade credit ratings as required by the Plan. The LLCs then would transfer the proceeds of the sale of the new money notes, less working capital reserves,DWR contracts that have been allocated to the Utility, but only if (1) the Utility receives a long-term issuer credit rating of at least A from S&P and A2 from Moody's, after giving effect to such assignment or assumption, (2) the CPUC first has made a finding that the DWR contracts being assumed are just and reasonable, and (3) the CPUC has acted to ensure that the Utility receives full and timely rate recovery of all costs of the DWR contracts over their lives without further review. The CPUC would retain the right to review administration and dispatch of the DWR contracts consistent with applicable law.

utility purposes, including to pay creditors in the Utility's Chapter 11 proceeding, have been included in the Utility's retail electric rates consistent with state and federal law, and are not subject to refund. The proposed settlement defines headroom as the Utility's total net after-tax income reported under GAAP, less earnings from operations, (as has been historically defined by PG&E Corporation ~~has agreed to contribute up to $700 million~~ in ~~cash to~~its earnings press release, a non-GAAP financial measure), plus after-tax amounts accrued for Chapter 11-related administration and Chapter 11-related interest costs, all multiplied by 1.67, provided the calculation will reflect the outcome of the Utility's ~~capital from~~2003 GRC. The proposed settlement notes that it is in the ~~issuance of equity or from other available sources,~~public interest to restore the ~~extent necessary~~Utility's financial health and to ~~satisfy the cash obligations of~~allow the Utility to recover, over a reasonable time, prior uncollected costs. For financial reporting purposes, these amounts that restore the Utility's financial health and recover previously written-off under-collected costs are referred to as headroom. The proposed settlement agreement provides that if headroom revenues accrued by the Utility during 2003 are greater than $875 million, pre-tax, the Utility would refund the excess to ratepayers. Further, if headroom revenues are less than $775 million, pre-tax, the CPUC would allow the Utility to collect the shortfall in ~~respect of allowed claims and required deposits into escrow for disputed claims, or to obtain investment-grade ratings~~rates. Headroom revenues for the debt to be issued by the Reorganized Utility and the LLCs. If PG&E Corporation is required to issue equity, PG&E Corporation's amended and restated credit agreement dated October 18, 2002 (Credit Agreement) will require mandatory prepayment of outstanding loans in an amount equal to the net cash proceeds from the issuance or sale of equity by PG&E Corporation. In addition, PG&E Corporation generally is prohibited bysix months ended June 30, 2003, were $237 million, pre-tax, as calculated under the terms of the ~~Credit Agreement~~proposed settlement agreement.

Dismissal of Filed Rate Case, Other Litigation, and Regulatory Proceedings -On or as soon as practicable after the later of the effective date of the Settlement Plan or the date the CPUC decision approving the settlement agreement no longer is subject to appeal, the Utility would dismiss with prejudice its "filed rate case" and withdraw the original plan of reorganization. In addition, the CPUC would resolve phase 2 of the pending Annual Transition Cost Proceeding in which the CPUC is reviewing the reasonableness of the Utility's procurement costs incurred during the energy crisis with no adverse impact on the Utility's cost recovery as filed.

Fees and Expenses -The proposed settlement agreement would require the Utility to reimburse PG&E Corporation and the CPUC after the date the Settlement Plan is confirmed for all of their respective professional fees and expenses incurred in connection with the Chapter 11 proceeding. Of such amounts, the amounts reimbursed to the CPUC could be recovered from ~~making investments~~ratepayers. As of June 30, 2003, PG&E Corporation has incurred expenses of approximately $121 million on the Utility's Chapter 11 proceeding.

Environmental Measures - The Utility would implement three environmental enhancement measures:

Term - The proposed settlement agreement generally would terminate nine years after the ~~terms~~effective date of the ~~loans or as required by applicable law or~~Settlement Plan, except that all vested rights of the ~~conditions adopted by~~parties under the ~~CPUC with respect to ho lding companies. To~~proposed settlement agreement would survive termination for the ~~extent lender consent is required, PG&E Corporation intends to negotiate with its lenders. Absent any required lender consent, PG&E Corporation intends to seek to refinance its indebtedness.~~purpose of enforcement.

~~If the~~The Settlement Plan isprovides that it would not be confirmed by the Bankruptcy Court unless and until the ~~Plan requires that certain~~following conditions ~~must be~~are satisfied or ~~waived before~~waived:

The Settlement Plan also provides that it would not become effective ~~including, among other conditions:~~unless and until the following conditions are satisfied or waived:

The last six conditions cannot be issued shall have been declared effective by the SEC. The Reorganized Utility shall have consummated the sale of its new securities to be sold under the Plan, and the new securities of each of ETrans, GTrans, and Gen shall have been priced and the trade date with respect to each shall have occurred.

~~If one or more of the conditions have not been satisfied or~~ waived, ~~the confirmation order would be vacated and the Utility's obligations with respect to claims and equity interests would remain unchanged.~~

~~In connection with the Plan,~~except that PG&E Corporation and the Utility ~~contend that bankruptcy law expressly preempts state law in connection with~~can waive the ~~implementation of a plan of reorganization. The Bankruptcy Court rejected this contention. PG&E Corporation and the Utility appealed this decision~~right to the U.S. District Court for the Northern District of California (District Court). The District Court reversed the Bankruptcy Court's ruling and remanded the case back to the Bankruptcy Court for further proceedings, ruling that the Bankruptcy Code expressly preempts "nonbankruptcy laws that would otherwise apply to bar, among other things, transactions necessary to implement the reorganization plan." The District Court entered judgment on September 19, 2002, and thefinality provisions regarding CPUC ~~and several other parties thereafter initiated an appeal to the U.S. Court of Appeals for the Ninth Circuit. The Ninth Circuit has scheduled arguments to be heard on May 14, 2003.~~

On February 27, 2003, the California counties of Alameda, Fresno, San Luis Obispo, Sonoma, and the City and County of San Francisco (collectively, the Counties) filed a motion for summary judgment denying confirmation of the Plan, arguing that the Plan is not feasible because it purports to transfer to Gen, or a subsidiary of Gen, the Utility's beneficial interests in the Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement (Trust). The Counties contend that the contemplated transfer is unlawful because the Utility's interests in the Trust do not constitute property of the Utility's estate. The Counties also argue that prior CPUC approval of the transfer is necessary but the Utility has not requested such approval. The Utility vigorously contests the Counties' allegations.

The CPUC and the Official Committee of Unsecured Creditors (OCC) jointly have proposed an alternative plan of reorganization (CPUC/OCC plan) for the Utility that does not call for realignment of the Utility's existing businesses. The alternative plan instead provides for the continued regulation of all of the Utility's current operations by the CPUC. The alternative plan proposes to satisfy all allowed creditor claims in full either through reinstatement or payment in cash, using a combination of cash on hand and the proceeds from the issuance of $7.3 billion of new senior secured debt and the issuance of $1.5 billion of new unsecured debt and preferred securities. The alternative plan also proposes to establish a $1.75 billion regulatory asset, which would be included in the Utility's rate base and would be amortized over ten years.

The CPUC/OCC plan also provides that it would not become effective until the Utility and the CPUC enter into a "reorganization agreement" under which the CPUC promises to establish retail electric rates on an ongoing basis sufficient to facilitate achieving and maintaining investment grade credit ratings for portions of the Utility's securities and to recover in rates (1) the interest and dividends payable on, and the amortization and redemption of, the securities to be issued under the alternative plan, and (2) certain recoverable costs (defined as the amounts the Utility is authorized by the CPUC to recover in retail electric rates in accordance with historical practice for all of its prudently incurred costs, including capital investment in property, plant and equipment, a return of capital, and a return on capital and equity to be determined by the CPUC from time to time in accordance with its past practices).

PG&E Corporation and the Utility believe the alternative plan is not credible or confirmable. PG&E Corporation and the Utility do not believe the alternative plan would restore the Utility or its debt securities to investment-grade status if the alternative plan is to become effective. Additionally, PG&E Corporation and the Utility believe the alternative plan would violate applicable federal and state law.

The trial on confirmation of the alternative plan began on November 18, 2002. The trial on the Plan began on December 16, 2002, with objections common to both plans slated for trial during the Plan trial. On March 4, 2003, the Bankruptcy Court ordered the Utility, the CPUC, and other parties involved in the confirmation trial to participate in settlement negotiations. On March 11, 2003, the Bankruptcy Court then issued an order staying nearly all the proceedings in the confirmation trial until May 12, 2003. On April 23, 2003, the Bankruptcy Court extended this stay for an additional 30 days. A status conference is scheduled for June 16, 2003.

~~The Utility is~~are unable to predict ~~which plan,~~whether and when the proposed settlement agreement will become effective or whether the Settlement Plan will be confirmed or implemented. If the Settlement Plan is not confirmed, or if ~~any,~~ the ~~Bankruptcy Court will confirm. If either plan is confirmed, implementation~~CPUC does not approve the proposed settlement agreement and related rates, or if the CPUC takes actions materially inconsistent with the proposed settlement agreement in pending regulatory proceedings associated with the recovery of transition costs and surcharge revenues, or the ~~confirmed plan may be delayed due~~allocation of DWR electricity to ~~appeals, CPUC actions or proceedings, or other regulatory hearings that~~customers of IOUs, as detailed in Note 6 below, then the Utility's financial condition and results of operations could be ~~required in connection with the regulatory approvals necessary to implement that plan,~~materially adversely affected. The settlement agreement and ~~other events. The uncertainty regarding~~Settlement Plan may also be affected by the outcome of the ~~bankruptcy proceeding~~California Supreme Court's consideration of questions certified to it by the Ninth Circuit regarding the validity of a settlement agreement between the CPUC and another California IOU, Southern California Edison Com pany (SCE). Several entities, including The Utility Reform Network (TURN) challenged the SCE settlement. Oral argument occurred before the California Supreme Court on May 27, 2003, and it is expected that the Court will issue a ruling by August 27, 2003. The Utility believes that, even if the California Supreme Court finds the SCE settlement violates state law, there are independent legal and factual reasons under which the proposed settlement agreement and the ~~related uncertainty around the plan of reorganization that is ultimately adopted~~Settlement Plan would still be valid under state and ~~implemented will have a significant impact on the Utility's future liquidity and results of operations.~~federal law. The ~~Utility is unable at this time to predict the outcome of its bankruptcy case or the effect~~effectiveness of the ~~reorganization process on~~Settlement Plan is not conditioned upon receiving a favorable ruling in the ~~claims of~~SCE case by the Utility's creditors or the interests of the Utility's preferred shareholders. However, the Utility believes, based on information presently available to it, that cash and cash equivalents on hand at March 31, 2003, of $3.6 billion and cash available from operations will provide sufficient liquidity to allow it to continue as a going concern through 2003.California Supreme Court.

~~Prior to~~On July ~~31, 2002, most of the various debt instruments of~~8, 2003, PG&E NEG and its subsidiaries carried investment-grade credit ratings as assigned by S&P and Moody's, two major credit rating agencies. Since July 31, 2002, PG&E NEG's rated entities have been downgraded several times. The result of these downgrades has left all of PG&E NEG consolidated rated entities and debt instruments at below investment-grade.

The downgrade of PG&E NEG's credit ratings impacted various guarantees and financial arrangements that require PG&E NEG to maintain certain credit ratings from S&P and/or Moody's. Because of the downgrades, PG&E NEG's counterparties have demanded PG&E NEG to provide additional securityfiled voluntary petitions for performance in the form of cash, letters of credit, acceptable replacement guarantees, or advanced funding of obligations. Other counterparties continue to have the right to make such demands. If PG&E NEG fails to provide this additional collateral within defined cure periods, PG&E NEG may be in default under contractual terms. In addition to agreements containing ratings triggers, other agreements allow counterparties to seek additional security for performance whenever such counterparty becomes concerned about PG&E NEG's or its subsidiaries' creditworthiness. PG&E NEG's credit downgrades constrained its access to additional capital and triggered increases in cost of indebtednes s under many of its outstanding debt arrangements.

The credit downgrades also impacted PG&E NEG's and its subsidiaries' ability to service their financial obligations by putting constraints on the ability to move cash from one subsidiary to another or to PG&E NEG itself. PG&E NEG's subsidiaries now must independently determine, in light of each company's financial situation, whether any proposed dividend, distribution, or intercompany loan is permitted and is in such subsidiary's interest.

The effects of the credit downgrades on PG&E NEG's debt facilities and other contractual arrangements are described below. Amounts required to be paid under debt agreements and other significant contractual commitments also are described below.

PG&E NEG is currently in default under various debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.7 billion, but this debt is non-recourse to PG&E NEG. On November 14, 2002, PG&E NEG defaulted on the repayment of the $431 million 364-day tranche of its corporate revolving credit facility (Corporate Revolver). Loans and letters of credit outstanding as of March 31, 2003,relief under the ~~two-year tranche~~provisions of the Corporate Revolver were $258 million, consisting of $185 million of letters of credit and $73 million of loans. The default under the Corporate Revolver also constitutes a cross-default as of March 31, 2003, under (1) PG&E NEG Senior Unsecured Notes ($1 billion outstanding), (2) its guarantee of a turbine revolving credit agreement ($205 million outstanding), and (3) various equity commitment guarantees totaling $960 million. In additio n, on November 15, 2002, PG&E NEG failed to pay a $52 million interest payment due under PG&E NEG Senior Unsecured Notes. PG&E NEG currently does not have sufficient cash to meet its financial obligations and has ceased making payments on its debt and equity commitments.

PG&E NEG, its subsidiaries, and their lenders have been engaged in discussions to restructure PG&E NEG's and its subsidiaries' debt obligations and other commitments since October 2002. No agreement has been reached yet and there can be no assurance that an agreement will be reached. Any restructuring agreement that may be reached would be implemented through a reorganization proceeding under Chapter 11 of the Bankruptcy ~~Code. Although~~Code in the Bankruptcy Court. In addition, on July 8, 2003, each of the following indirect wholly owned subsidiaries of PG&E NEG filed a voluntary petition for relief under the provisions of Chapter 11 of the Bankruptcy Code in the Bankruptcy Court: PG&E ET Investments Corporation; PG&E Energy Trading Holdings Corporation; PG&E Energy Trading-Power, L.P.; and ~~its~~PG&E Energy Trading - Gas Corporation; (collectively, the "ET Companies"); and, separately, USGen New England, Inc. (USGenNE). On July 29, 2003, two other subsidiaries, ~~are continuing their efforts to maximize cash~~Quantum Ventures and ~~reduce liabilities, such efforts are not expected to restore the financial condition~~PG&E Energy Services Ventures, Inc., each filed voluntary Chapter 11 petitions. The Chapter 11 case of USGenNE is being administered separately from those of PG&E NEG and ~~its~~other subsidiaries. ~~Absent a negotiated agreement,~~

Pursuant to Chapter 11 of the ~~lenders may exercise their default remedies or force~~Bankruptcy Code, PG&E NEG, and ~~certain~~these subsidiaries retain control of ~~its subsidiaries into an involuntary proceeding under~~their assets and are authorized to operate their businesses as debtors-in-possession while being subject to the jurisdiction of the Bankruptcy ~~Code. Notwithstanding the status of current negotiations,~~Court. Additionally, on July 8, 2003, PG&E NEG filed a plan of reorganization after reaching an agreement in principle as to the plan's key terms with an informal group of creditors that included major creditors, several bondholders, and agents under certain unsecured facilities, acting in their individual capacities. PG&E NEG's proposed plan of ~~its subsidiaries also may elect to voluntarily seek protection under~~reorganization would not restructure the indebtedness of any of the debtors, other than PG&E NEG. If PG&E NEG's plan of reorganization is confirmed by the Bankruptcy ~~Codeas early as the second quarter of 2003. Although~~Court and implemented, PG&E Corporation ~~continues to provide assistance to PG&E NEG, its subsidiaries and its lenders~~no longer would have any equity interest in ~~their negotiations, management does not expect the outcome of any bankruptcy proceeding involving~~ PG&E NEG or any of its ~~subsidiaries to have~~subsidiaries. It is anticipated that the Chapter 11 plans for USGenNE and the ET Companies will be filed at a ~~material adverse effect~~later date.

As of June 30, 2003, PG&E NEG had consolidated assets of $6.8 billion and liabilities of $8.3 billion. As of June 30, 2003, PG&E Corporation's net investment in PG&E NEG was a negative $1.1 billion, including approximately $400 million of intercompany receivables.

The accompanying PG&E Corporation Consolidated Financial Statements include the consolidated results of PG&E NEG through June 30, 2003. As a result of PG&E NEG's Chapter 11 filing and the resignation of PG&E Corporation's representatives who previously served on the ~~financial condition~~PG&E NEG Board of Directors and their replacement with Board members who are not affiliated with PG&E Corporation, PG&E Corporation no longer retains significant influence over the ongoing operations of PG&E NEG. Accordingly, effective July 8, 2003, PG&E Corporation no longer will consolidate PG&E NEG's financial results and will begin accounting for its investment in PG&E NEG using the cost method. In accordance with the cost method, PG&E Corporation no longer will recognize its equity share in the income or losses of PG&E NEG and will record its investment in and advances to PG&E NEG as a non-current liability on the ~~Utility.~~Consolidated Balance Sheets. This investment will not be affected by changes in PG&E NEG's future financial results, other than (1) investments in or dividends from PG&E NEG, or (2) income taxes PG&E Corporation may be required to pay if the Interal Revenue Service disallows certain deductions or tax credits attributable to PG&E NEG and its subsidiaries for the past tax years that were incorporated into PG&E Corporation's consolidated tax returns.

If PG&E NEG's plan of reorganization is implemented and PG&E Corporation's equity in PG&E NEG is eliminated, PG&E Corporation will bring its net investment in PG&E NEG to zero and, as a result, recognize a one-time non-cash gain to earnings. The amount of such potential gain cannot be estimated at this time.

PG&E NEG is currently in default under various debt agreements and guaranteed equity commitments totaling approximately $5.6 billion, of which approximately $2.8 billion is debt that is non-recourse to PG&E NEG. PG&E NEG currently does not have sufficient cash to meet its financial obligations and has ceased making payments on its debt and equity commitments.

The schedule below summarizes PG&E NEG's and its ~~subsidiaries'~~subsidiaries outstanding debt in default and long-term debt ~~as of March 31,~~at June 30, 2003, and December 31, 2002:

	Outstanding Balance At

Description	June 30, 2003		December 31, 2002


Amounts classified as Debt in default	$	4,691	$	4,230
Amount related to liabilities held for sale, classified as current		75			75
Long-term debt, classified as current		11	17
Long-term debt		611	630

Total Debt in default and Long-term debt	$	5,388	$		4,952

~~For the period ended March 31,~~ -As of June 30, 2003, accrued interest was recorded on the following debt instruments:

Facility-In December 2001, PG&E NEG entered into a $1.075 billion ~~5-year~~five-year non-recourse credit facility for a portfolio of generating projects held by GenHoldings I, LLC (GenHoldings), ~~a wholly-owned~~an indirect subsidiary of PG&E NEG. The credit facility, which was increased to ~~$1.5~~$1.460 billion on April 5, 2002, is secured by the Millennium, Harquahala Generating Company, LLC (Harquahala), Covert Generating Company, LLC (Covert), and Athens Generating Company, LLC (Athens) generating projects. The facility was ~~intended to be~~ used to reimburse PG&E NEG and lenders for a portion of the construction costs already incurred on these projects and to fund a portion of the balance of the construction costs through completion.

GenHoldings ~~has~~ defaulted under its credit agreement by failing to make equity contributions to fund a portion of the construction draws for the Athens, Harquahala, and Covert projects. In November and December 2002, GenHoldings' lenders executed waivers and amendments to the credit agreement under which they agreed to continue to waive GenHoldings' equity default until ~~March 31,~~June 30, 2003, and increased loan commitments to cover such shortfall.

In connection with the lenders' waiver of various defaults and additional funding commitments, PG&E NEG ~~has~~ agreed to cooperate with any reasonable proposal by the lenders regarding disposition of the equity in or assets of ~~any or~~ all of the PG&E NEG subsidiaries holding the Athens, Covert, Harquahala, and Millennium projects.

As of March 21, 2003, the lenders executed a waiver letter extending to June 30, 2003, the waiver of GenHoldings' equity default. In addition, the waiver letter also waives other existing defaults in order to permit the continued availability of loan facilities to fund construction and operation of the projects until such time as a transfer of the projects to the GenHoldings lenders may be completed. An event of default ~~will~~would occur if ~~such transfer is~~these projects are not ~~accomplished~~transferred to the lenders or their designees by ~~June 30, 2003. A default~~August 29, 2003, which would trigger lender remedies including the right to foreclose on the ~~Millennium, Harquahala, Athens, and Covert~~ projects. The administrative agent has the discretion to extend this date to September 30, 2003.

~~Under the waiver,~~ PG&E NEG has ~~re-affirmed~~reaffirmed its guarantee of GenHoldings' remaining obligation to make equity contributions to these projects of approximately $355 million. ~~Neither PG&E NEG nor GenHoldings currently expects to have sufficient funds to make this payment. The requirement to pay $355 million~~This guarantee will remain an obligation of PG&E NEG ~~that would survive~~after the transfer of the projects.

Facilities-In September 1999 and March 2000, Lake Road Generating Company, LP (Lake Road) and La Paloma Generating Company, LLC (La Paloma) entered into ~~Participation Agreements~~participation agreements to finance the construction of the two plants. In November 2002, Lake Road and La Paloma defaulted on their obligations to pay interest and swap payments. In addition, as a result of PG&E NEG's downgrade to below investment grade by both S&P and Moody's, PG&E NEG, as guarantor of certain debt obligations of Lake Road and La Paloma, became required to make equity contributions to Lake Road ~~and La Paloma~~ of $230 million and $375 million ~~respectively. The lenders have accelerated all debt existing prior~~ to ~~December 11, 2002, including the guaranteed portion of the debt and made a payment under the PG&E NEG guarantee. Neither PG&E NEG, Lake Road nor~~ La ~~Paloma has sufficient funds to make these payments.~~Paloma.

As of December 4, 2002, ~~PG&E NEG~~Lake Road and ~~certain subsidiaries~~La Paloma entered into various agreements with ~~the~~their respective lenders ~~for each of the Lake Road and La Paloma generating projects~~ providing for (1) funding of construction costs required to complete the La Paloma facility, and (2) additional working capital facilities to enable each subsidiary to timely pay for its fuel requirements and to provide its own collateral to support natural gas pipeline capacity reservations and independent transmission system operator requirements, as well as for general working capital purposes. Lenders extending new credit under these agreements have received liens on the projects that are senior to the existing lenders' liens. These agreements ~~provide,~~require, among other things, ~~that~~ the ~~failure to~~ transfer ~~right, title and interest in, to and under~~of the Lake Road and La Paloma projects and all associated contracts and agreements to the respective lenders by June 9, 2003. On June 8, 2003, ~~will constitute a default under the agreements. The failure~~an amendment extended this date to transfer the facilities would entitle the lenders to accelerate the new indebtedness and exercise other remedies. The requirement to pay $230 million and $375 million for Lake Road and La Paloma, respectively, will remain an obligation of PG&E NEG that would survive the transfer of the projects.

On May 7, 2002, Attala Generating Company LLC (Attala Generating), an indirect ~~wholly-owned~~wholly owned subsidiary of PG&E NEG, completed a $340 million sale and leaseback transaction whereby it sold and leased back a 526-megawatt (~~MW)~~(MW) generation facility ~~(Facility)~~(Attala Facility) in Mississippi to two third-party special-purpose entities (SPEs). These entities funded the acquisition of their undivided interests in the Attala Facility through proceeds from the issuance of debt and equity. The SPEs funded $103 million, or approximately 30 percent of the total fair value of the Attala Facility on the transaction date, from the issuance of equity. The related transaction was accounted for as a lease because the owners of the SPEs had made an initial substantive residual equity capital investment that was intended to be at risk during the entire term of the lease.

During January 2003, the SPEs distributed cash to their equity holders, which resulted in the SPEs no longer meeting the substantive equity at risk criteria, under current accounting requirements. PG&E NEG now consolidates the assets and liabilities of the SPEs.

The consolidation of the SPEs resulted in an increase in assets of $62 million, representing the estimated fair value of the Attala Facility and related inventories, and debt of $237 million, representing the bonds issued to finance the sale-leaseback transaction. As the liabilities of the SPEs exceed their assets, a pre-tax charge to earnings of $175 million was recorded in the first quarter of 2003.

In January 2003, the FASB issued ~~Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46).~~FIN 46. See Note 1, "General - Adoption of New Accounting Policies," for a more complete description of FIN 46. PG&E NEG currently is evaluating the impacts of FIN 46's initial recognition, measurement, and disclosure provisions on its Consolidated Financial Statements when these requirements become effective by the beginning of the third quarter of 2003.

PG&E ~~NEG~~Corporation believes that, upon the adoption of FIN 46, itPG&E NEG will not be required to continue to consolidate the SPEs associated with the sale-leaseback of the Attala Facility, since it has neither an equity investment nor a significant variable interest in the SPEs. Depending on the method of adopting FIN 46 by PG&E NEG, either the difference between the book values of the SPEs' assets and liabilities will be recognized through earnings, or first quarter 2003 financial statements will be restated to eliminate the impact of initially consolidating the SPEs. Future earnings also may ~~also~~ be impacted by the accrual of any probable payments under the Attala guarantee arrangement disclosed in Note ~~6 of the Notes to the Consolidated Financial Statements.~~6.

In connection with the terms of a proposed settlement of all pending disputes among Shaw Group Inc. (Shaw), Harquahala, ~~Generating Company, LLC (Harquahala),~~ Covert, ~~Generating Company, LLC (Covert)~~ and PG&E NEG, PG&E NEG ~~has~~ recognized a pre-tax charge of approximately $32 million for anticipated legal settlement ~~costs.~~costs in the first quarter ended March 31, 2003. Harquahala and Covert are indirect subsidiaries of PG&E NEG.

The Harquahala generating facility, owned by Harquahala, is a ~~1,092-MW~~1,092 MW plant located in Tonopah, Arizona, with about 88 percent of the construction complete. Covert generating facility, owned by Covert, is a ~~1,170-MW~~1,170 MW plant located in Covert, Michigan, with about 84 percent of construction complete. The equity in Covert and Harquahala is owned by GenHoldings. On August 13, 2001, Harquahala and Covert entered into engineering procurement and construction contracts (EPCs) with Shaw to design, procure materials and equipment for, and construct these generating facilities.

During November and December 2002, Harquahala commenced arbitration against Shaw seeking a declaration that it was not obligated to withhold payments from a certain third party connected with the construction of the facility. Subsequently, Shaw commenced arbitration against Covert and Harquahala to recover the ~~value of~~fees and expenses associated with certain change order requests. In addition, Shaw filed a lawsuit against Harquahala, Covert, PG&E NEG, and NEG Construction Finance Company, LLC (CFC), alleging that it had not received adequate assurance of payment from PG&E NEG.

Under the terms of ~~the proposed~~a definitive settlement agreement, effective May 16, 2003, PG&E NEG ~~will pay~~paid approximately ~~$32~~$32.5 million to Shaw, and the EPC contracts ~~will be~~were increased in the aggregate by $65 million (the balance funded by the lenders),. In addition, the completion deadlines ~~will be~~were extended, the cost-sharing agreements and related guarantees ~~will be~~were terminated, and PG&E NEG's completion guarantees to the lenders ~~will be~~were released. The ~~parties are now negotiating definitive agreements.~~remaining $32.5 million is an obligation of Covert and Harquahala under their construction financing arrangements.

The Mantua Creek project is a ~~nominal~~ 897 MW combined cycle merchant power plant located in the Township of West Depford, New Jersey. Due to liquidity ~~concerns,~~constraints, PG&E NEG ~~could~~ no longer could provide equity contributions to the project and beginning in the fourth quarter of 2002, began to suspend or terminate contracts with vendors. At December 31, 2002, PG&E NEG wrote off capitalized development and construction costs of $257 million and established an additional accrual of $22 million for charges and associated termination costs. ~~For~~In the ~~period ending March 31,~~six months ended June 30, 2003, various termination cost accruals were adjusted as settlements occurred resulting in an approximate $8 million reduction in impairment expense.

On June 26, 2003, PG&E GTN, PG&E ET, and DTE Georgetown, LLC (DTE) entered into a termination agreement that terminated a tolling agreement between DTE and PG&E ET dated May 23, 2000. In consideration for a payment of approximately $30 million by PG&E ET, the termination agreement releases and discharges PG&E ET from any and all obligations under the tolling agreement and PG&E GTN from any and all obligations under its guarantee of PG&E ET's obligations, subject to restoration of PG&E GTN's guarantee obligation in the limited event that DTE may be required to disgorge amounts received from PG&E ET. Under the tolling agreement, PG&E ET would have had to make capacity payments totaling approximately $64 million over the next seven years. PG&E NEG recorded this $30 million payment as a charge to impairment expense in the three months ended June 30, 2003.

- In September 1998, ~~USGen New England, Inc. (USGenNE)~~USGenNE acquired the non-nuclear generating assets of the New England Electric System (NEES) for approximately $1.8 billion. These assets included:

Consistent with its previously announced strategy ~~to dispose~~of disposing of certain merchant assets, in December 2002, the Board of Directors of PG&E Corporation approved management's plans for the proposed sale of USGenNE. Under the provisions of SFAS No. 144, the equity of USGenNE ~~has been~~is accounted for as an asset held for ~~sale at December 31, 2002.~~sale. This requires that the asset be recorded at the lower of fair value, less costs to sell, or book value. Based on the then current estimated fair value (based on the estimated proceeds) of a sale of USGenNE, PG&E NEG recorded a pre-tax loss of $1.1 billion in the fourth quarter of 2002. ~~PG&E NEG recorded an additional pre-tax loss on disposal of $23 million in the first quarter of 2003.~~ It ~~was~~is anticipated that ~~the~~ arrangements for the disposition of the USGenNE assets ~~would~~will be made ~~during 2003.~~during2003. However, as a result of required regulatory approval by the FERC, it is anticipated that any disposals will not be consummated until 2004. The operating results from USGenNE are being reported as discontinued operations in the ~~PG&E Corporation~~ Consolidated Financial Statements of ~~Operations for the three months ended March 31, 2003,~~PG&E NEG and ~~2002.~~PG& E Corporation. Also, under the provisions of SFAS No. 144, no depreciation has been recorded on ~~the restated assets.~~these assets held for sale.

On September 17 and 28, 2001, PG&E NEG purchased Mountain View Power Partners, LLC and Mountain View Power Partners II, LLC, respectively (collectively referred to as Mountain View), from SeaWest Wind Power, Inc. These companies own 44- and 22-MW wind energy projects, respectively, near Palm Springs, California (SeaWest). PG&E NEG contracted with SeaWest for the operation and maintenance of the wind units. Total consideration for these two companies was $92 million. The two companies were merged on October 1, 2002. The power is sold to the DWR under a 10-year contract.

- In December 2002, the Board of Directors of PG&E Corporation approved the sale of Mountain ~~View.~~View Power Partners, LLC and Mountain View Power Partners II, LLC, which had been merged on October 1, 2002 (collectively referred to as Mountain View). On December 18, 2002, a subsidiary of PG&E NEG entered into an agreement to sell Mountain View to Centennial Power, Inc. The sale occurred on January 3, 2003. PG&E NEG received $102 million in proceeds for the sale of Mountain View, resulting in a $19 million pre-tax gain.

Under the provisions of SFAS No. 144, Mountain View is accounted for as an asset held for ~~sale at March 31, 2003, and December 31, 2002.~~sale. The operating results ~~from~~and gains on sale of Mountain View are ~~being~~ reported as discontinued operations in the ~~PG&E Corporation~~ Consolidated Financial Statements of ~~Operations for the three months ended March 31, 2003,~~PG&E NEG and ~~2002.~~PG&E Corporation.

- On March 18, 2003, PG&E Energy Trading-Gas Corporation (ET-Gas), a subsidiary of PG&E NEG, completed the sale of 100 percent of the stock of PG&E Energy Trading, Canada Corporation (ET Canada) to Seminole Canada Gas Company, a Nova Scotia unlimited liability company (Seminole). Seminole transferred approximately $86 million at closing to ET-Gas and several of its affiliates, representing the purchase price and the return of collateral posted by ET-Gas and ET Canada to support ET Canada's energy trading transactions, plus interest. Most of the proceeds were used to repay principal and interest on an outstanding loan of $76 million to another affiliate.

Seminole also ~~has agreed within 30 days after the closing to replace~~replaced certain letters of credit issued to support ET Canada's energy trading transactions and ~~to obtain~~obtained the release of ET-Gas and its affiliates, including PG&E GTN and PG&E NEG, from obligations under guarantees ~~issued for~~supporting the ~~same reasons.~~letters of credit. Seminole has indemnified ET-Gas for any liability under the letters of credit or the guarantees. As previously disclosed, in the fourth quarter of 2002, PG&E NEG and PG&E Corporation recorded a $25 million pre-tax loss on the anticipated disposition of ET Canada. In the first quarter of 2003, an additional loss of $3 million pre-tax on disposal was recorded. Under the provisions of SFAS No. 144, ET Canada is accounted for as a discontinued operation.

Ohio Peakers- On June 30, 2003, PG&E Dispersed Generating Company (DG), an indirect subsidiary of PG&E NEG, and American Municipal Power-Ohio Inc. (Amp Ohio) entered into a contract whereby Amp Ohio will purchase DG's three Ohio generating plants, Galion, Napoleon, and Bowling Green, plus the attached spare turbines and parts and the associated rights to expand the Bowling Green and Napoleon plants (collectively referred to as the Ohio Peakers) for $7 million. The closing of this transaction is expected to occur in August 2003, after FERC approval is received. Under the provisions of SFAS No. 144, the Ohio Peakers are accounted for as assets held for sale. This requires that the assets be recorded at the lower of fair value, less costs to sell, or book value. At the same time the asset sales agreement was executed, PG&E ET and Amp Ohio executed and closed on an agreement to terminate the tolling agreement between the two parties, associated with the Bowling Green Plant. PG& amp;E ET received $5.5 million to terminate the tolling agreement. Based on the estimated proceeds from the sales agreement and including the tolling agreement termination payment, PG&E NEG recorded a pre-tax loss on disposal ~~was recorded.~~

The following table reflects the ~~combined~~ operating results of the combined USGenNE, Mountain View, ~~and~~ ET Canada, ~~before reclassification to discontinued operations~~and the Ohio Peakers for the three and six months ended ~~March 31,~~June 30, 2003, and 2002:

	Three months ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	----------------------------
(in millions)	2003		2002		2003		2002		2003		2002
	------------		------------
Operating Revenues	$	122	$	216	$	194	$	195	$	317	$	412
Operating Expenses					141		117		313		248
Cost of commodity sales and fuel	172		131
Operations, maintenance, and management	52		63		60		68		113		132
Depreciation and amortization	-		17		1		19		1		37
Other operating expenses					2		-		2		-
	-------------		-------------
Total operating expense	$	224	$	211		204		204		429		417
	-------------		-------------
Operating Income (Loss)	(102)		5		(10)		(9)		(112)		(5)
Interest income	7		10		8		11		15		21
Interest expense	(1)		-		-		(1)		(1)		(1)
Other expense, net	(4)		(2)		(2)		(4)		(6)		(6)
	-------------		-------------
Income (Loss) Before Income Taxes	$	(100)	$	13		(4)		(3)		104		9
Income tax expense (benefit)	(35)		5
Income tax expense					-		(3)		-		2
	-------------		-------------
Earnings (Loss) from Assets classified as Discontinued Operations	$	(65)	$	8	$	(4)	$	-	$	(104)	$	7
	=======		=======

The following table reflects the components of assets and liabilities held for sale of USGenNE ~~before reclassification to discontinued operations~~and Ohio Peakers at ~~March 31,~~June 30, 2003, and the combined ~~components of assets and liabilities held for sale of~~ USGenNE, Mountain View, ~~and~~ ET Canada, and Ohio Peakers at December 31, 2002:

Included in the assets and liabilities held for sale summary above, are certain amounts paid to USGenNE related to the assumption of power supply agreements and certain purchase obligations assumed by USGenNE from the acquisition that occurred in 1998.

As discussed in Note 3, PG&E NEG isfinancial results will no longer be consolidated in those of PG&E Corporation following the ~~process~~July 8, 2003, Chapter 11 filing of ~~reducing and unwinding its trading positions. Additionally, asset hedge positions associated with~~PG&E NEG. Upon deconsolidation, the ~~merchant plants~~only risk management activities reported will ~~either remain with the assets or~~ be ~~terminated.~~ related to Utility non-trading activities.

PG&E NEG has significantly reduced its energy trading operations ~~in an ongoing effort to raise cash~~ and ~~reduce debt. PG&E NEG's objective~~ is to limit its asset trading and risk management activities to only what is necessary for energy management services to facilitate the transition of PG&E NEG's merchant generation facilities through their sale, transfer, or abandonment process. PG&E NEG will then further reduce and transition to retain onlyretaining limited capabilities necessary to ensure fuel procurement and power logistics for PG&E NEG's retained independent power plant ~~operations.~~operations and to serve USGenNE's needs.

At ~~March 31,~~June 30, 2003, PG&E Corporation had cash flow hedges of varying durations associated with commodity price risk, interest rate risk, and foreign currency risk, the longest of which extend through ~~December 2011,~~November 2003, March 2014, and December 2004, respectively.

~~The amount~~ PG&E Corporation has incurred cumulative derivative losses of $29 million on its commodity hedges, ~~included in Accumulated Other Comprehensive Income or Loss (OCI), net of tax, at March 31, 2003, was a loss of $36 million. The amount of~~$50 million on its interest rate hedges, and $1 million on its foreign currency hedges, which are included in OCI ~~net of tax,~~ at ~~March 31, 2003, was a loss of $49 million. The amount of foreign currency hedges included in OCI, net of tax, at March 31, 2003, was a loss of $1 million.~~June 30, 2003.

PG&E Corporation's net derivative losses included in OCI at ~~March 31,~~June 30, 2003, were ~~$86~~$80 million, of which approximately ~~$45~~$38 million is expected to be reclassified into earnings within the next 12 months based on the contractual terms of the contracts or the termination of the hedge position. The actual amounts reclassified from OCI to earnings will differ as a result of market price changes. ~~The Utility did not have any cash flow hedges at March 31, 2003, or at March 31, 2002.~~ PG&E Corporation's ineffective portion of changes in amounts of cash flow hedges was immaterial for the three and six months ended ~~March 31,~~June 30, 2003, and ~~March 31,~~June 30, 2002.

The schedule below summarizes the activities affecting ~~Accumulated Other Comprehensive Income (Loss),~~OCI, net of tax, from derivative instruments:

(in millions)
Three months ended
March 31, 2003

Three months ended
March 31, 2002
------------------------------
-----------------------------
PG&E
Corporation

Utility

PG&E
Corporation

Utility
----------------
-----------
----------------
-----------
Derivative gains (losses) included in accumulated other
   comprehensive income (loss) at beginning of period

$

(90)

$

- -

$

36

$

- -
Net gain (loss) from current period hedging transactions
   and price changes
(1)
-

(75)
-
Net reclassification to earnings
5
-

5
-
---------------
------------
---------------
------------
Derivative gains (losses) included in accumulated other
   comprehensive income at end of period
(86)
-

(34)
-
Foreign currency translation adjustment
-
-

(5)
(2)
Other
-
-

(1)
-
---------------
------------
---------------
------------
Accumulated other comprehensive income (loss) at end
   of period
$
(86)
$
-
$
(40)
$
(2)
=========
=======
=========
=======

(in millions)	Three months ended June 30, 2003				Three months ended June 30, 2002

	PG&E Corporation		Utility		PG&E Corporation		Utility

Derivative losses included in accumulated other comprehensive income (loss) at beginning of period	$	(86)	$	-	$	(34)	$	-
Net loss from current period hedging transactions and price changes		(4)		-		(9)		-
Net reclassification to earnings		10				-		-

Derivative losses included in accumulated other comprehensive income at end of period		(80)		-		(43)		-
Foreign currency translation adjustment		-		-		(2)		-
Retirement plan remeasurement (Note 8)		(60)		(60)		-		-

Accumulated other comprehensive loss at end of period	$	(140)	$	(60)	$	(45)	$	-

(in millions)	Six months ended June 30, 2003				Six months ended June 30, 2002

	PG&E Corporation		Utility		PG&E Corporation		Utility

Derivative losses included in accumulated other comprehensive income (loss) at beginning of period	$	(90)	$	-	$	36	$	-
Net loss from current period hedging transactions and price changes		(5)		-		(84)		-
Net reclassification to earnings		15		-		5		-

Derivative losses included in accumulated other comprehensive income at end of period		(80)		-		(43)		-
Foreign currency translation adjustment		-		-		(2)		-
Retirement plan remeasurement (Note 8)		(60)		(60)		-		-

Accumulated other comprehensive loss at end of period	$	(140)	$	(60)	$	(45)	$	-

Normally, most non-trading activity earnings are recognized on an accrual basis as revenues are earned and as expenses are incurred. For example, the effective portion of contracts accounted for as cash flow hedges have no mark-to-market effect on earnings; these contracts are presented on a mark-to-market basis on the balance sheet in price risk management (PRM) assets and liabilities and OCI. Other non-trading contracts are exempt from the SFAS No. 133 fair value requirements under the normal purchases and sales exception and thus have no mark-to-market effect on earnings.

Cash flow hedge accounting was discontinued for commodity cash flow ~~hedges~~hedge derivatives of PG&E NEG on January 1, 2003. Accordingly, ~~such non-trading activities~~prospective changes in the fair value of these discontinued cash flow hedge derivatives affect PG&E NEG's earnings on a mark-to-market ~~basis. PG&E NEG recognizes the prospective change in fair value relating to commodity hedges and~~basis along with the ineffective portion of ~~the changes in the fair value of~~ all cash flow ~~hedges in earnings.~~hedges. PG&E NEG ~~also~~ has certain non-trading derivative contracts that ~~while they are meant for non-trading purposes,~~ do not qualify for cash flow hedge accounting or ~~for~~ the normal purchases and sales exception to SFAS No. 133. These derivatives are reported in earnings on a mark-to-market basis. These contracts consist primarily ~~consist~~ of those derivative commodity contracts for which normal purchases and sales treatment was disallowed upon PG&E NEG's implementation of ~~Derivative Implementation Group (DIG)~~DIG C15 and C16 effective April 1, 2002.

PG&E NEG's pre-tax earnings include losses of $18 million and gains of $32 million for the ~~period~~three- and six-month periods ended ~~March 31,~~June 30, 2003, ~~include gains of $50 million~~ related to commodity hedges, previously deferred in OCI, after it became probable that the forecasted transactions will not occur.

At June 30, 2003, the Utility had cash flow hedges associated with natural gas commodity price risk. These contracts are presented at fair value on the Utility's Consolidated Balance Sheets in PRM assets and regulatory liabilities. At June 30, 2002, the Utility did not have any cash flow hedges.

The Utility has certain non-trading derivative contracts that do not qualify for cash flow hedge accounting or the normal purchase and sales exception to SFAS No.133. These derivatives are reported in earnings on a mark-to-market basis.

Unrealized gains and losses from trading activities, including the reversal of unrealized gains and losses previously recognized on contracts that go to settlement or delivery, are presented on a net basis in operating revenues. Realized gains and losses from trading activities also are presented on a net basis in operating revenues, beginning in the third quarter of 2002, as more fully described in Note 1 of the Notes to the Consolidated Financial Statements.

Gains and losses on trading contracts affect PG&E Corporation's gross margin in the accompanying PG&E Corporation Consolidated Statements of Operations on ~~an unrealized,~~a mark-to-market ~~basis as the fair value of the forward positions on these contracts fluctuate.~~basis. Settlement or delivery on a contract generally does not result in incremental net income recognition because the profit or loss on a contract is recognized in income on ~~an unrealized,~~a mark-to-market basis during the periods before settlement occurs.

Gains and losses on trading contracts affect PG&E Corporation's cash flow when these contracts are settled. Net realized gains reported in the table below primarily reflect the net effect of contracts that have been settled in cash. Net realized gains also include certain non-cash items, including amortization of option premiums that were paid or received in cash in earlier periods, but are considered realized when the related options are exercised or ~~expire.~~expired.

PG&E Corporation's net gains ~~(loss)~~(losses) on trading activities are as follows:

	Three months ended				Six months ended
	June 30,				June 30,

(in millions)	2003		2002		2003		2002

Trading activities:
Unrealized losses, net	$	(41)	$	(48)	$	(33)	$	(53)
Realized gains (losses), net	(7)		34		(40)		78

Total	$	(48)	$	(14)	$	(73)	$	25

PRM assets and liabilities on the accompanying PG&E Corporation Consolidated Balance Sheets reflect the aggregation of the fair values of outstanding contracts. These fair values are calculated on a mark-to-market basis for contracts that will be settled in future periods. PRM assets and liabilities at ~~March 31,~~June 30, 2003, include amounts for trading and non-trading activities, as described below:

Non-trading activities include certain long-term contracts that are not included in PG&E Corporation's trading portfolio but, due to certain pricing provisions and volumetric variability, are unable to receive hedge accounting treatment or the normal purchases and sales exception, as outlined by interpretations of SFAS No. 133. PG&E Corporation has certain other non-trading derivative commodity contracts for the physical delivery of purchases and sales quantities transacted in the normal course of business. These other non-trading activities include contracts that are exempt from SFAS No. 133 fair value requirements under the normal purchases and sales exemption, as described previously. Although the fair value of these other non-trading contracts is not required to be presented on the balance sheet, revenues and expenses generally are recognized in income using the same timing and basis as are used for the non-trading activities accounted for as cash flow hedges. Hence, revenues are recognized as earned and expenses are recognized as incurred.

Credit risk is the risk of loss that PG&E Corporation and the Utility would incur if counterparties failed to perform their contractual ~~obligations (these~~obligations. These obligations are reflected as Accounts Receivable - Customers, net; notes receivable included in Other Noncurrent Assets - Other; ~~Price Risk Management (PRM)~~PRM assets; and Assets Held For Sale on the Consolidated Balance Sheets of PG&E Corporation and the Utility, as ~~applicable).~~applicable. PG&E Corporation and the Utility conduct business primarily with customers or vendors, referred to as counterparties, in the energy industry. These counterparties include other ~~investor-owned utilities,~~IOUs, municipal utilities, energy trading companies, financial institutions, and oil and gas production companies located in the United States and Canada. This concentration of counterparties may impact PG&E Corporation's and the Utility's overall exposure to credit risk because their counterparties may be similarly affected by economic or regulatory ~~chang es,~~changes, or other changes in conditions.

PG&E Corporation and the Utility manage their credit risk in accordance with the PG&E Corporation Risk Management Policy. This ~~establishes~~established processes for assigning credit limits to counterparties before entering into agreements with significant exposure to PG&E Corporation and the Utility. These processes include an evaluation of a potential counterparty's financial condition, net worth, credit rating, and other credit criteria as deemed appropriate, and are performed at least annually.

Credit exposure is calculated daily, and in the event that exposure exceeds the established limits, PG&E Corporation and the Utility take immediate action to reduce the exposure, or obtain additional collateral, or both. Further, PG&E Corporation and the Utility rely heavily on master agreements that require the counterparty to post security, referred to as credit collateral, in the form 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 and the Utility calculate gross credit exposure for each counterparty as the current mark-to-market value of the contract (that is, the amount that would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, prior to the application of the counterparty's credit collateral.

During the ~~three months~~period ended ~~March 31,~~June 30, 2003, PG&E Corporation's credit risk decreased, as compared to December 31, 2002, primarily due to contract terminations with PG&E NEG counterparties. During the ~~three months~~period ended ~~March 31,~~June 30, 2003, the Utility's credit risk ~~increased~~decreased, as compared to December 31, 2002, primarily due ~~primarily~~ to ~~an increase in commodity prices and to downgrades~~the receipt of some counterparties' credit ratings to levels below investment grade. The downgrades increase the Utility's credit risk because any collateral provided by these counterparties in the form of corporate guarantees or eligible securities may be of lesser or no value. Therefore, in the event these counterparties failed to perform under their contracts, the Utility may facepayment from a greater potential maximum loss. In contrast, the Utility does not face any additional risk if counterparties' credit collateral is in the form of cash or letters of credit, as this collateral is not affected bypreviously terminated contract with a ~~credit rating downgrade.~~

During the ~~three months~~three- and six-month periods ended ~~March 31,~~June 30, 2003, PG&E Corporation and the Utility recognized no losses due to the contract defaults or bankruptcies of counterparties.

At ~~March 31,~~June 30, 2003, PG&E Corporation had no single counterparty that represented greater than 10 percent of PG&E Corporation's net credit exposure. At ~~March 31,~~June 30, 2003, the Utility had one ~~investment-grade~~investment grade counterparty that represented 17 percent of the Utility's net credit exposure and one below-investment grade counterparty that represented 11 percent of the Utility's net credit exposure.

The schedule below summarizes PG&E Corporation's and the Utility's credit risk exposure to counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange provides for contract settlement on a daily basis), as well as PG&E Corporation's and the Utility's credit risk exposure to counterparties with a greater than 10 percent net credit exposure, at ~~March 31,~~June 30, 2003, and December 31, 2002:

(in millions)
Gross Credit
Exposure Before
Credit Collateral⁽¹⁾
Credit
Collateral⁽²⁾
Net Credit
Exposure⁽²⁾
Number of
Counterparties
>10 percent
Net Exposure of
Counterparties
>10 percent

------------------------
----------------
----------------
--------------------
----------------------
At March 31, 2003

PG&E Corporation
$
789
$
198
$
591
$
-
$
-
Utility ⁽³⁾
306
116
190
1
32
At December 31, 2002
PG&E Corporation
$
1,165
$
195
$
970
$
-
$
-
Utility ⁽³⁾
288
113
175
2
55

The schedule below summarizes the credit quality of PG&E Corporation's and the Utility's net credit risk exposure to counterparties at ~~March 31,~~June 30, 2003, and December 31, 2002.

PG&E Corporation has regional concentrations of credit exposure to counterparties that conduct business primarily throughout North America. The Utility has a regional concentration of credit risk associated with its receivables from residential and small commercial customers in Northern California. However, the risk of material loss due to nonperformance from these customers is not considered likely. Reserves for uncollectible accounts receivable are provided for the potential loss from nonpayment by these customers based on historical experience. At ~~March 31,~~June 30, 2003, the Utility had a net regional concentration of credit exposure totaling ~~$190~~$165 million to counterparties that conduct business primarily throughout North America.

PG&E Corporation has substantial financial commitments and contingencies in connection with agreements entered into supporting the Utility's ~~and~~operating activities. PG&E Corporation has limited financial commitments relating to PG&E NEG's operating ~~construction, and development~~ activities. These commitments ~~and contingencies~~ are discussed more fully in the PG&E ~~Corporation~~Corporation's and ~~Utility~~Utility's combined 2002 Annual Report on Form 10-K, as amended. The following summarizes PG&E Corporation's, the Utility's, and PG&E NEG's material contingencies and ~~cancelled,~~canceled, new, and significantly modified commitments since the combined 2002 Annual Report on Form 10-K, as amended, was filed.

Natural Gas Supply and Transportation Commitments- The Utility purchases natural gas directly from producers and marketers in both Canada and the United States. The composition of the portfolio of natural gas procurement contracts has fluctuated, generally based on market conditions.

The Utility also has long-term gas transportation service agreements with various Canadian and interstate pipeline companies. These companies are responsible for transporting the Utility's gas to the California border. The total demand charges that the Utility will pay each year may change due to changes in tariff rates. These agreements include provisions for payment of fixed demand charges for reserving firm pipeline capacity as well as volumetric transportation charges.

At June 30, 2003, the Utility's obligations for natural gas purchases and gas transportation services were as follows:

Since the Utility is in Chapter 11 and its credit ratings are below investment grade, the Utility uses several different credit arrangements for the purpose of purchasing natural gas. The Utility has a $10 million standby letter of credit and has pledged its gas customer accounts receivable. The core gas inventory may be pledged but only if the Utility's gas customer accounts receivable are less than the amount that the Utility owes to the gas suppliers. Through June 30, 2003, the accounts receivable pledge has been sufficient. The CPUC authorized the Utility to pledge its gas accounts receivable and core inventory, if necessary, until the earlier of:

At June 30, 2003, the pledged amount of gas accounts receivable was $220 million.

Transmission Control Agreement- The Utility entered into a Transmission Control Agreement (TCA) with the ISO and others. As a transmission owner, the Utility is required to give two years notice if it wishes to withdraw from the TCA. Under this agreement, the transmission owners, which also include SCE and San Diego Gas & Electric Company, assign control and operation of their electric transmission systems to the ISO. In addition, as a party to the TCA, the transmission owners are responsible for the costs of the Reliability Must-Run (RMR) Agreements between the ISO and owners of the plants subject to RMR contracts (RMR plants). Under the RMR Agreements, RMR plants must remain available to generate electricity when needed for transmission system reliability upon the ISO's demand.

At June 30, 2003, the ISO has RMR agreements that obligate the Utility for approximately $911 million during the period July 1, 2003, to June 30, 2005.

It is possible that the Utility may receive a refund of RMR costs previously paid to the ISO. In June 2000, an Administrative Law Judge (ALJ) at the FERC issued an initial decision that would require the subsidiaries of the Mirant Corporation (Mirant) that are parties to three RMR contracts with the ISO to refund to the ISO, and the ISO to refund to the Utility, excess payments for availability of Mirant's generating units under the RMR contracts. If the FERC were to affirm the ALJ's initial decision, the Utility would expect refunds, with interest, of approximately $300 million. Any refunds received would be used to reduce previously under-collected transition and procurement costs or to lower future reliability services rates depending on the time period covered by the refunds. On July 14, 2003, Mirant filed a petition for reorganization under Chapter 11 of the Bankruptcy Code. The Utility is unable to predict at this time when the FERC will issue a final decision on this issue, what the outcome of the FERC's decision will be, and the amount of any refunds, which may be impacted by Mirant's Chapter 11 filing, the Utility will ultimately receive.

Electricity Purchases to Meet Demand- On January 1, 2003, the Utility resumed the function of procuring electricity to meet the portion of its customers' needs that is not covered by the combination of the allocation of electricity from existing DWR contracts and the Utility's own electric generation resources and contracts. To meet this requirement, the Utility entered into contracts for fuel supply, capacity, and transmission rights. In order to enter into these contracts, the Utility has posted collateral with the California ISO and several other counterparties. These contracts, with terms of one year or less, did not have a material impact on the Utility's commitments previously disclosed in its 2002 Annual Report on Form 10-K, as amended.

In June 2003, the CPUC issued a decision that requires each IOU to increase procurement of renewable energy by at least 1 percent per year. By the end of 2017, each IOU must be procuring at least 20 percent of its total electricity from renewable resources. The decision states that the Utility is not obligated to procure additional renewable energy until it is creditworthy and that the Utility will accumulate an Annual Procurement Target (APT) based on 1 percent of retail sales, each year, starting in 2003, until it receives an investment grade credit rating. When the Utility receives an investment grade credit rating it will be required to enter into procurement contracts for renewable energy to meet its accumulated APT. Although the Utility cannot predict what the terms, including price, of such contracts would be, the decision requires that the procurement price under such contracts be at or below a market price benchmark established by the CPUC after the bids have been received. If the Utilit y exceeds its APT, it can apply the excess to meet the APT in future years. For under-procurement, the decision allows IOUs to carry over an annual deficit of 25 percent to the next three years without explanation. Failure to meet minimum APTs without prior CPUC approval would result in an automatic penalty of $0.05 per kilowatt-hour(kWh), subject to an annual penalty cap of $25 million.

In addition to the outstanding balances under the credit facilities described in Note 3, PG&E NEG and certain subsidiaries are required to reimburse amounts drawn under letters of credit issued by financial institutions under certain financing facilities. As a result of PG&E NEG's Chapter 11 filing, the financial institutions are no longer obligated to provide letters of credit facilities. The following table lists the various letter of credit facilities:

PG&E ET entered into tolling agreements with several counterparties under which, at its discretion, PG&E ET supplied the fuel to the power plants and then sold the plant's output in the competitive market. Payments to counterparties would be reduced if the plants did not achieve agreed-upon levels of performance. The face amount of PG&E NEG's and its subsidiaries' guarantees relating to PG&E ET's tolling agreements is approximately $565 million. PG&E ET entered into tolling agreements with: (1) Liberty Electric Power, L.P. (Liberty) guaranteed by both PG&E NEG and PG&E GTN for an aggregate amount of up to $140 million, (2) Calpine Energy Services, L.P. (Calpine) for which no guarantee is in place, (3) Southaven Power, LLC (Southaven) guaranteed by PG&E NEG for up to $175 million, and (4) Caledonia Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million. On July 8, 2003, PG&E ET petitioned the Bankruptcy Court to reject all remaining tolling agr eements. On August 6, 2003, the Bankruptcy Court approved PG&E ET's motion and the Liberty, Southaven, and Caledonia tolling agreements are now terminated.

Under each tolling agreement, determination of the termination payment is based on a formula that takes into account a number of factors including market conditions such as the price of power and the price of fuel. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. The dispute resolution process could take as long as six months to more than a year to complete. The Bankruptcy Court may resolve any damages claim or permit such arbitration to proceed.

DTE-Georgetown, LLC- On June 26, 2003, PG&E GTN, PG&E Energy Trading - Power, LP (PGET), and DTE-Georgetown, LLC(DTE) entered into a termination agreement that terminated a tolling agreement between DTE and PGET dated May 23, 2000. In consideration for a payment of approximately $30 million by PGET, the termination agreement releases and discharges PGET from any and all obligations under the tolling agreement and PG&E GTN from any and all obligations under its guarantee of PGET's obligations, subject to restoration of PG&E GTN's guarantee obligation in the limited event that DTE may be required to disgorge amounts received from PGET. Under the tolling agreement, PGET would have had to make capacity payments totaling approximately $64 million over the next seven years.

Liberty - On August 6, 2003, the Bankruptcy Court approved PG&E ET's motion to reject the Liberty tolling agreement, and that agreement is now terminated. Whether and to the extent either Liberty or PG&E ET may be found liable for termination payments under the Liberty tolling agreement is subject to dispute. If liability is established and PG&E ET is responsible for termination payments to Liberty, PG&E GTN will be the primary guarantor for any amounts due to Liberty. Under the terms of the guarantee to Liberty, PG&E GTN is potentially liable for termination payments up to the maximum amount of the guarantee, $140 million. On July 22, 2003, Liberty issued a $4.4 million payment demand to PG&E GTN under the guarantee, ostensibly for a capacity payment due from PG&E ET to Liberty arising prior to PG&E ET's filing for bankruptcy protection. In addition, on July 30, 2003, Liberty sent an invoice for a termination payment of approximately $177 million to PG&a mp;E ET.

Southaven and Caledonia Tolling Agreements-PG&E ET signed a tolling agreement with Southaven dated as of June 1, 2000, and Caledonia dated September 30, 2000, under which PG&E ET was required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment grade as defined in the tolling agreement. The amount of the guarantee does not exceed $175 million for Southaven and $250 million for Caledonia. By letter dated August 31, 2002, Southaven and Caledonia advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment grade as defined in the tolling agreement, and because PG&E ET had failed to provide, within 30 days from the downgrade, substitute credit support that meets the requirement of the tolling agreement. Southaven and Caledonia have the right to te rminate the agreement and seek a termination payment. In addition, PG&E ET provided Southaven and Caledonia with a notice of default respecting Southaven's and Caledonia's performance under the tolling agreement and concerning the inability of the facility to inject its output into the local grid. Southaven and Caledonia have not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.

On February 7, 2003, Southaven and Caledonia filed emergency petitions to compel arbitration or, in the alternative, for a temporary restraining order and preliminary injunction with the Circuit Court of Montgomery County, Maryland. On March 3, 2003, the court issued an order ruling that PG&E ET must continue to perform under the agreements. PG&E ET appealed this decision to an intermediate Maryland appellate court. However, on April 8, 2003, the highest appellate court in Maryland issued on its own motion an order taking jurisdiction of the appeal. This action is currently stayed as a result of PG&E ET's Chapter 11 filing on July 8, 2003. The Southaven and Caledonia tolling agreements were the subject of a motion to reject filed by PG&E ET with the Bankruptcy Court on July 8, 2003. On August 6, 2003, the Bankruptcy Court granted PG&E ET's motion, and terminated the Southaven and Caledonia tolling agreements.

The Utility has significant gain and loss contingencies related to ~~California electric industry restructuring and~~ its Chapter 11 filing. ~~See~~

As a result of frozen rates, at December 31, 2000, the Utility had accumulated a total of approximately $4.1 billion, after-tax, in under-collected purchased power and generation-related transition costs. This amount was charged to earnings at that time because the Utility could no longer conclude that such costs were probable of collection through regulated rates. In 2001 and 2002, as a result of stabilized wholesale electricity prices and the CPUC-authorized surcharges discussed below, the Utility's total generation-related electric revenues were greater than its generation-related costs, resulting in the partial recovery of under-collected purchased power and generation-related transition costs that were previously written off. As of December 31, 2002, the outstanding balance of the under-collected purchased power and generation-related transition costs was $2.2 billion, after-tax. During the first quarter of 2003, generation-related costs exceeded generation-related revenues due to lower wint er consumption and lower winter rates. During the second quarter of 2003, generation-related revenues returned to levels in excess of generation-related costs. As of June 30, 2003, the outstanding balance of the Utility's under-collected purchased power and generation-related transition costs amounted to $2.1 billion, after-tax, excluding interest and other Chapter 11-related costs. Generation-related costs in excess of generation-related revenues continue to be expensed as they are incurred. Under the proposed settlement agreement in the Utility's Chapter 11 proceeding, the CPUC would agree to establish a new regulatory asset to restore the Utility to financial health (see Note 2). The balances in the Utility's transition cost balancing account as of January 1, 2004, would have no further impact on the Utility's retail electric rates and would be subject to no further review by the CPUC except for verification of recorded balances.

In January 2001, the CPUC increased electric rates by $0.01 per kWh, in March 2001 by another $0.03 per kWh, and in May 2001 by an additional $0.005 per kWh. The use of these surcharge revenues was restricted to "ongoing procurement costs" and "future power purchases." In November and December 2002, the CPUC approved decisions modifying the restrictions on the use of revenues generated by the surcharges and authorizing the Utility to record amounts related to the surcharge revenues as an offset to unrecovered transition costs. Based on these CPUC decisions and an agreement between the CPUC and another IOU, SCE, in which SCE was allowed to use its $0.005 per kWh surcharge to offset its DWR revenue requirement, the Utility has continued to recognize revenues related to the $0.01, $0.03, and $0.005 surcharges after the statutory end of the retail electric rate freeze, which was March 31, 2002, even without considering the proposed settlement agreement in the Utility's Chapter 11 proceed ing (discussed in Note 2). As such, the Utility has not recorded a regulatory liability or a refund reserve for these surcharge revenues, or any portion thereof, in its financial statements. From January 2001 to June 30, 2003, the Utility recognized total surcharge revenues of $6.5 billion, pre-tax.

Under the proposed settlement agreement discussed in Note 2, the CPUC would agree and acknowledge that the headroom, surcharge, and base revenues accrued or collected by the Utility through and including December 31, 2003, are the property of the Utility's Chapter 11 estate, have been or will be used for utility purposes, including to pay creditors in the Utility's Chapter 11 proceeding, have been included in the Utility's retail electric rates consistent with state and federal law, and are not subject to refund. The proposed settlement defines headroom as the Utility's total net after-tax income reported under GAAP, less earnings from operations, (as has been historically defined by PG&E Corporation in its earnings press release, a ~~discussion~~non-GAAP financial measure), plus after-tax amounts accrued for Chapter 11-related administration and Chapter 11-related interest costs, all multiplied by 1.67, provided the calculation will reflect the outcome of the Utility's 2003 GRC. The proposed settlement notes tha t it is in the public interest to restore the Utility's financial health and to allow the Utility to recover, over a reasonable time, prior uncollected costs. For financial reporting purposes, these amounts that restore the Utility's financial health and recover previously written-off under-collected costs are referred to as headroom. The proposed settlement agreement provides that if headroom revenues accrued by the Utility during 2003 are greater than $875 million, pre-tax, the Utility would refund the excess to ratepayers. Further, if headroom revenues are less than $775 million, pre-tax, the CPUC would allow the Utility to collect the shortfall in rates. Headroom revenues for the six months ended June 30, 2003, were $237 million, pre-tax, as calculated under the terms of the proposed settlement agreement.

The Utility's ultimate recovery of its previously written-off under-collected purchased power and generation-related transition costs if the proposed settlement agreement and Settlement Plan are not implemented and the validity of the CPUC's agreements under the proposed settlement agreement regarding headroom, surcharge and base revenues collected by the Utility through and including December 31, 2003, may depend upon the California Supreme Court's consideration of questions certified to it by the Ninth Circuit regarding the legality of recovery of under-collected costs by SCE under a settlement and stipulated federal court judgment with the CPUC. The CPUC represented to the court that, in part, as a result of California (AB) 6X, which prevented the Utility from divesting generation assets, it has the authority to allow the Utility and SCE to recover under-collected purchased power and generation-related transition costs beyond the end of the rate freeze. The settlement reached by the CPUC and SCE provides that the CPUC would maintain SCE's rates at their current levels (beyond the end of the rate freeze) until the earlier of the date that SCE recovered its transition costs or December 31, 2003. Several entities, including TURN, have challenged this settlement and the ratemaking adopted by the CPUC to implement the settlement, arguing, among other things, that the recovery of SCE's under-collected costs in retail rates under the settlement violates the provisions of AB 1890 prohibiting post-freeze recovery of transition and procurement costs. Oral argument occurred before the California Supreme Court on May 27, 2003, and it is expected that the Court will issue a ruling by August 27, 2003.

Even if the California Supreme Court were to rule that the SCE settlement violates state law and, therefore, California IOUs are not permitted to recover their procurement and transition costs after the end of the rate freeze, such a ruling would not affect the Utility's claim that it has a right to recover such costs under the federal filed rate doctrine, which is currently pending before the federal courts. Under the proposed settlement agreement, on or as soon as practicable after the latter of the effective date of the Settlement Plan or the date that CPUC approval of the proposed settlement agreement is no longer subject to appeal, the Utility would dismiss with prejudice the filed rate case.

Further, PG&E Corporation and the Utility believe that, even if the California Supreme Court finds the SCE settlement violates state law, there are independent legal andfactual reasons under which the proposed settlement agreement and the Settlement Plan would still be valid under state and federal law. The effectiveness of the Settlement Plan is not conditioned on receiving a favorable ruling in the SCE case by the California Supreme Court.

If the Settlement Plan contemplated in the proposed settlement agreement in the Utility's Chapter 11 proceeding is not implemented, it is possible that at some future date the CPUC, either in response to certain judicial decisions, or on its own initiative, may change its interpretation of law or otherwise seek to change the Utility's overall retail electric rates retroactively. As stated above, the Utility has not provided reserves for potential refunds of any of these ~~matters.~~surcharge revenues as of June 30, 2003. If the CPUC requires the Utility to refund any of these revenues in the future, the Utility's earnings could be materially affected.

In July 2003, a CPUC Commissioner issued a proposed decision that proposes to find that the retail electric rate freeze ended on January 18, 2001. The proposed decision also provides that the CPUC would determine the extent and disposition of costs previously defined as uneconomic, transition or stranded, in a separate proceeding. The proposed decision contemplates that the separate proceeding would also determine whether the recovery of these costs has been fully addressed or resolved in the Utility's Chapter 11 proceeding or in other CPUC proceedings. The Utility has filed comments suggesting that the CPUC defer its decision on these issues pending the CPUC's consideration of the proposed settlement agreement and the implementation of the Settlement Plan. The Utility cannot predict the ultimate outcome of this proceeding.

In September 2002, the CPUC issued a decision to allocate the electricity provided under existing DWR contracts to the customers of the IOUs. This decision required the Utility, along with the other IOUs, to begin performing all the day-to-day scheduling, dispatch, and administrative functions associated with the DWR contracts allocated to the IOUs' respective resource portfolios by January 1, 2003. The DWR retains legal and financial responsibility for these contracts.

Under the proposed settlement agreement, the Utility would agree to accept an assignment of or to assume legal and financial responsibility for the DWR contracts only if (1) the Utility receives a long-term issuer credit rating of at least A from S&P and an issuer credit rating of at least A2 from Moody's after giving effect to such assignment or assumption, (2) the CPUC first makes a finding that the DWR allocated contracts are just and reasonable, and (3) the CPUC first acts to ensure that the Utility receives full and timely rate recovery of all costs of the DWR contracts over their life without further review. The CPUC would retain the right to review administration and dispatch of the DWR contracts consistent with applicable law. The State of California has stated publicly that it does not intend to transfer full legal title of, and responsibility for, the DWR electricity contracts to the IOUs until they are in a position where they will be financially able to absorb the contracts. However, if the proposed settlement agreement is not approved and either the State of California or the CPUC grants the DWR the authority to transfer legal title of the DWR contracts to the Utility without having first met the Utility's conditions, the Utility's results of operations could be adversely affected.

The Utility has several types of nuclear insurance for its Diablo Canyon Power Plant (DCPP) and Humboldt Bay Power Plant (HBPP). The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). NEIL is a mutual insurer owned by utilities with nuclear facilities. Under this insurance, if any nuclear generating facility insured by NEIL suffers severe losses, the NEIL Board of Directors could require the Utility to pay additional annual premiums of up to $32 million for DCPP to cover property damages and business interruption ~~for DCPP~~ and up to $1.4 million for HBPP to cover property ~~damages for HBPP.~~damages.

Under federal law, the Price-Anderson Act (Act), public liability claims from a nuclear incident are limited to $9.5 billion. As required by the Act, the Utility has purchased the maximum available public liability insurance of $300 million for DCPP. The balance of the $9.5 billion of liability protection is covered by a loss-sharing program (secondary financial protection) among utilities owning nuclear reactors. Under the Act, secondary financial protection is required for all reactors of 100 MW or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to $88 million per reactor, with payments in each year limited to a maximum of $10 million per incident until the Utility has fully paid its share of the liability. Since the Utility has two nuclear reactors of over 100 MW, 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. In February 2003, a provision extending the ~~Price-Anderson~~ Act through the end of 2003 was adopted by the ~~United States~~U.S. Congress. No other material terms of the ~~Price-Anderson~~ Act changed as a result of the provision.

Additionally, the Utility has purchased $53.3 million of private liability insurance for HBPP and has a $500 million indemnification from the ~~NRC~~Nuclear Regulatory Commission (NRC) for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of private liability insurance for HBPP.

The Utility is self-insured for workers' compensation. The Utility must deposit collateral with the State Department of Industrial Relations (DIR) to maintain its status as a self-insurer for workers' compensation claims made against the Utility. Acceptable forms of collateral include surety bonds, letters of credit, cash, or securities. The Utility currently provides collateral in the form of approximately $365 million in surety bonds.

In February 2001, several surety companies provided cancellation notices because of the Utility's financial situation. The DIR has not agreed to release the canceling sureties from their obligations for claims occurring prior to the cancellation and has continued to apply the ~~cancelled~~canceled bond amounts, totaling $185 million, towards the $365 million amount of collateral. ~~The Utility was able to supplement the difference through three~~Three additional active surety bonds totaling $180 ~~million.~~million make up the Utility's collateral. At ~~March 31,~~June 30, 2003, the ~~cancelled~~canceled bonds have not impacted the Utility's self-insured status under California law. PG&E Corporation has guaranteed the Utility's reimbursement obligation associated with these surety bonds and the Utility's underlying obligation to pay workers' compensation claims.

In 2002, the CPUC ordered the Utility to create certain electric balancing accounts to track specific electric-related amounts, ~~primarily~~ including revenue shortfalls from baseline allowance increases and costs related to the self-generation incentive program, for which the CPUC has not yet determined a specific recovery method. In the decisions ordering the creation of these balancing accounts, the CPUC indicated that the recovery method of these amounts would be determined in the future. Because the Utility cannot conclude that the amounts in these balancing accounts are considered probable of recovery in future rates, the Utility has reserved these balances by recording a charge against earnings. As of June 30, 2003, the reserve associated with these balancing accounts was approximately $220 million.

Because the Utility acts as a collection agent for the DWR, amounts collected on behalf of the DWR (related to its revenue requirement) are excluded from the Utility's revenues. Until the CPUC modifies the current frozen rate structure or until the approval of the proposed settlement agreement and new rates under that settlement are implemented, changes to the DWR's 2001, 2002, or 2003 revenue requirement may materially affect the Utility's future earnings.

In December 2002, the CPUC issued a decision allocating approximately $2 billion of the DWR's 2003 $4.5 billion total statewide power charge-related revenue requirement to the Utility's customers. This revenue requirement includes the cost associated with the DWR contracts allocated to the Utility's customers effective January 1, 2003. In April 2003, the Utility and the DWR entered into a CPUC-approved operating agreement that supersedes the December 2002 operating order. (The December 2002 operating order required the Utility to perform the operational, dispatch, and administrative functions for the DWR's allocated contracts beginning on January 1, 2003.) The operating agreement provides that the Utility will begin passing through additional revenues to the DWR consistent with the DWR's October 2002 and March 2003 requests for amendments to the formula that determines the amount of remittances to the DWR contained in the May 2002 servicing order but subject to the outcome of the CPUC's consideration of the DWR's requests. As of June 30, 2003, the Utility had accrued an additional $516 million, pre-tax, obligation for pass-through revenues to the DWR. The Utility had accrued $369 million, pre-tax, at December 31, 2002, and $539 million, pre-tax, at March 31, 2003 ~~the reserve~~ for these ~~balances~~additional pass-through revenues to the DWR. During the second quarter of 2003, the Utility remitted $74 million of these pass-through revenues to the DWR and accrued an additional $51 million.The ultimate remittance of the $516 million amount accrued as of June 30, 2003, depends upon whether the CPUC grants the DWR's request for changes to the May 2002 servicing order (which was ~~approximately $190 million.~~

~~Letters of Credit~~revised in December 2002) and whether such changes would be retroactive to January 2001, the date that the DWR began purchasing power for the Utility's customers.

In ~~addition~~July 2003, the DWR submitted a supplemental 2003 revenue requirement to the outstanding balances under the credit facilities described in Note 3, PG&E NEG has commitments available under facilities to issue letters of credit. The following table lists the various letter of credit facilities that have the capacity to issue letters of credit :

PG&E ET entered into tolling agreements with several counterparties under which it, at its discretion, supplies the fuel to the power plants and then sells the plant's output in the competitive market. Payments to counterparties are reduced if the plants do not achieve agreed-upon levels of performance. The face amount of PG&E NEG's and its subsidiaries' guarantees relating to PG&E ET's tolling agreements is approximately $600 million. The tolling agreements are with: (1) Liberty Electric Power, L.P. (Liberty) guaranteed by both PG&E NEG and PG&E GTN for an aggregate amount of up to $150 million, (2) DTE-Georgetown, LLC (DTE) guaranteed by PG&E GTN for up to $24 million, (3) Calpine Energy Services, L.P. (Calpine) for which no guarantee is in place, (4) Southaven Power, LLC (Southaven) guaranteed by PG&E NEG for up to $175 million, and (5) Caledonia Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million.

Liberty -Liberty has provided notice to PG&E ET that the ratings downgrade of PG&E NEG constituted a material adverse change under the tolling agreement, requiring PG&E ET to replace the guarantee and post security inCPUC reducing the amount of ~~$150 million. PG&E ET has not posted such security. Under~~ the ~~terms~~total 2003 statewide power charge-related revenue the DWR was anticipating to receive by approximately $1 billion. The CPUC is responsible for determining how to allocate the reduced revenue requirement among the customers of the ~~guarantees, Liberty has~~three California IOUs. The requested reduction expressly assumes that the ~~right~~Utility would remit an additional estimated cash payment of $539 million, which was accrued as of March 31, 2003, to ~~terminate~~ the ~~agreement~~DWR in 2003. TheALJ in this proceeding indicated that the $539 million assumed remittance amount is an estimate and ~~seek recovery~~not a final number. The ALJ also indicated that, in connection with the proposed 2003 DWR revenue requirement reduction, the CPUC may consider reducing utility rates overall in order to pass through the savings to customers. The CPUC expects to consider a proposed decision during the third quarter of 2003.On August 1, 2003, another CPUC ALJ issued a ~~termination~~draft decision that, if approved by the CPUC, would modify the May 2002 and December 2002 DWR servicing orders to require the Utility to remit an additional cash payment to the DWR for the period retroactive to January 2001 as discussed above. The draft decision would not specify the amount to be remitted but instead defers the issue to the 2003 DWR supplemental revenue requirement proceeding, where offsetting reductions to the DWR's revenue requirements and remittances for 2003 are being considered. The draft decision would not determine whether the Utility should pay interest on the additional payment, but would defer to both the DWR and the Utility to resolve the issue, subject to CPUC determination if the parties cannot agree. The draft decision is subject to comment by parties before being considered by the CPUC.A separate proceeding will consider a ~~maximum amount of up~~revision or adjustment for the revenue requirements remitted to ~~$150 million. Liberty first must proceed against PG&E NEG's guarantee,~~the DWR for 2002 and ~~can demand payment under PG&E GTN's guarantee only if (1) PG&E NEG is in bankruptcy,~~2001 costs. At that time, the CPUC may also consider a revision or ~~(2) Liberty has made a payment demand on PG&E NEG which remains unpaid five business days after~~adjustment to the ~~payment demand is made. In addition, PG&E ET has provided notices to Liberty of several breaches~~allocation of the ~~tolling agreement by Liberty and~~DWR's 2003 revenue requirement. The Utility cannot predict the ultimate outcome of this matter.

The Utility has ~~advised Liberty that, unless cured, these breaches would constitute~~ a ~~default under the agreement. If these defaults rema~~lawsuit pending in ~~uncured, PG&E ET has the right to terminate the agreement and seek recovery of~~ a ~~termination payment.~~

~~DTE-Georgetown -By letter dated October 14, 2002, DTE provided notice to PG&E ET~~California court, asking that the ~~downgrade~~DWR be precluded from imposing its revenue requirements on the Utility and its customers until the DWR can demonstrate that its revenue requirements are "just and reasonable," as legally required. The lawsuit is scheduled to be considered by the court during the third or fourth quarter of PG&E GTN constituted a material adverse change under the tolling agreement between PG&E ET and DTE and that PG&E ET was required to post replacement security within ten days. By letter dated October 23, 2002, PG&E ET advised DTE that because there had not been a material adverse change with respect to PG&E GTN within the meaning of the tolling agreement, PG&E ET was not required to post replacement security. If PG&E ET was required to post replacement security and it failed to do so, DTE would have the right to terminate the tolling agreement and seek recovery of a termination payment.

Calpine -The tolling agreement states that on or before October 15, 2002, Calpine was to have issued a full notice to proceed under its construction contract to its engineering, procurement, and construction contractor for the Otay Mesa facility. On October 16, 2002, PG&E ET asked Calpine to confirm that it had issued this full notice to proceed and Calpine was not able to do so to the satisfaction of PG&E ET. Consequently, PG&E ET advised Calpine by letter dated October 30, 2002, that it was terminating the tolling agreement effective November 29, 2002. Calpine has indicated that this termination was improper and constituted a default under the agreement, but has not taken any further action.

Southaven and Caledonia Tolling Agreements -PG&E ET signed a tolling agreement with Southaven dated as of June 1, 2000, under which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing an investment-grade guarantee from PG&E NEG as defined in the tolling agreement. The amount of the guarantee now does not exceed $175 million. By letter dated August 31, 2002, Southaven advised PG&E ET that it believed an event of default under the tolling agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade as defined in the tolling agreement, and because PG&E ET had failed to provide, within 30 days from the downgrade, substitute credit support that met the requirements of the tolling agreement. Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET provided Southaven with a notice of default re specting Southaven's performance under the tolling agreement and concerning the inability of the facility to inject its output into the local grid. Southaven has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.

In addition, PG&E ET signed a tolling agreement with Caledonia dated as of September 20, 2000, under which PG&E ET is required to provide credit support, as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade, as defined in the tolling agreement. The amount of the guarantee does not exceed $250 million. By letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an event of default under the tolling agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade, as defined in the tolling agreement, and because PG&E ET had failed to provide, within 30 days from the downgrade, substitute credit support that met the requirements of the tolling agreement. Caledonia has the right to terminate the tolling agreement and seek a termination payment. In addition, PG&E ET provided Caledonia with a notice of default respecting Caledonia's perf ormance under the tolling agreement and concerning the inability of the facility to inject its output into the local grid. Caledonia has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.

PG&E ET is not able to predict whether the counterparties will seek to terminate the agreements or whether the Court will grant the requested relief. Accordingly, it is not able to predict whether or the extent to which these proceedings will have a material adverse effect on PG&E NEG's financial condition or results of operations.

Under each tolling agreement, determination of the termination payment is based on a formula that takes into account a number of factors, including market conditions such as the price of power and the price of fuel. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. The dispute resolution process could take as long as six months to more than a year to complete. To the extent that PG&E ET did not pay these damages, the counterparties could seek payment under the guarantees for an aggregate amount not to exceed $600 million. PG&E NEG ~~is unable to predict whether counterparties will seek to terminate their tolling agreements. PG&E NEG currently does not expect to be able to pay any termination payments that may become due.~~

PG&E NEG and certain subsidiaries have provided guarantees as of ~~March 31,~~June 30, 2003, to approximately ~~188~~96 counterparties in support of PG&E ET's energy trading and non-trading activities related to PG&E NEG's merchant energy portfolio in the face amount of ~~$2.2~~$1.1 billion. During the second quarter, due to wind down of the trading operations, PG&E NEG and its subsidiaries have canceled guarantees amounting to $1.5 billion. Typically, the overall exposure under these guarantees is only a fraction of the face value of these guarantees, since not all counterparty credit limits are fully used at any time. ~~As of March 31, 2003, PG&E NEG and its rated subsidiaries' aggregate exposure under these guarantees was approximately $150 million.~~ The amount of such exposure varies daily depending on changes in market prices and net changes in position. ~~In light of the downgrades, some counterparties have sought and others may seek replacement security to collateralize the exposure guaranteed by PG&E NEG and~~With its ~~subsidiaries. PG&E GTN and~~Chapter 11 filing on July 8, 2003, PG&E ET ~~have terminated~~defaulted on numerous trading agreements. The amounts due as a result of these defaults will be determined and resolved in the ~~arrangements pursuant to which PG&E GTN provided guarantees on behalf of PG& amp;E ET such that PG&E GTN will provide no new guarantees on behalf of PG&E ET.~~

~~At March 31, 2003, PG&E ET's estimated exposure not covered by a guarantee (excluding exposure under tolling agreements) is approximately $96 million.~~

To date, PG&E ET has met those replacement security requirements properly demanded by counterparties and has not defaulted under any of its master trading agreements, although one counterparty has alleged a default. No demands have been made upon the guarantorscontext of PG&E ET's obligations under these trading agreements. In the past, PG&E ET has been able to negotiate acceptable arrangements and reduce its overall exposure to counterparties when PG&E ET or its counterparties have faced similar situations. There can be no assurance that PG&E ET can continue to negotiate acceptable arrangements in the current circumstances. PG&E NEG cannot quantify with any certainty the actual future calls on PG&E ET's liquidity. PG&E NEG's and its subsidiaries' ability to meet these calls on their liquidity will vary with market price volatility, uncertainty with respect to PG&E NEG's financial condition, and the degree of liquidity in the energy markets. The actual calls for collatera l will depend largely upon the ability to enter into forbearance agreements and pre- and early-pay arrangements with counterparties, the continued performance of PG&E NEG companies under the underlying agreements with counterparties, whether counterparties have the right to demand such collateral, the execution of master netting agreements and offsetting transactions, changes in the amount of exposure, and the counterparties' other commercial considerations.

PG&E NEG ~~has~~ provided guarantees related to other obligations by PG&E NEG companies to counterparties for goods or services. PG&E NEG does not believe that it has significant exposure under these guarantees. The most significant of these guarantees ~~relates~~relate to performance under certain construction contracts. In the event PG&E NEG is unable to provide any additional or replacement security that may be required as a result of rating downgrades, the counterparty providing the goods or services could suspend performance or terminate the underlying agreement and seek recovery of damages. These guarantees represent guarantees of subsidiary obligations for transactions entered into in the ordinary course of business. Some of the guarantees relate to the construction or development of PG&E NEG's power plants and pipelines. These guarantees are described below.

PG&E NEG has issued guarantees to construction financing lenders for the performance of the contractors building the Harquahala and Covert generating projects for up to $555 million.

Additionally, PG&E NEG has issued $100 million of guarantees to the construction contractor of the Harquahala and Covert projects to cover certain separate cost-sharing arrangements.

As a result of the settlement of the Shaw Litigation, these guarantees have been terminated.

PG&E NEG has provided a $300 million guarantee to support a tolling agreement that a ~~wholly-owned~~wholly owned subsidiary, Attala Energy Company, LLC, has entered into with another ~~wholly-owned~~wholly owned subsidiary, Attala ~~Generating Company, LLC.~~

The balance of the guarantees are for commitments undertaken by PG&E NEG or ~~its~~ subsidiaries in the ordinary course of business for services such as facility and equipment leases, ash disposal rights, and surety bonds.

A claim has been asserted on behalf of PG&E NEG's estate that PG&E NEG is entitled to be compensated for any tax savings achieved by PG&E Corporation as a result of the incorporation of PG&E NEG's losses and deductions in PG&E Corporation's consolidated federal tax return under an alleged implied tax sharing agreement between PG&E Corporation and PG&E NEG or otherwise. In May 2003, PG&E Corporation received a return of $533 million from the Internal Revenue Service for an overpayment of 2002 estimated federal income taxes resulting from losses and deductions incurred at PG&E Corporation, the Utility, and PG&E NEG and its subsidiaries, of which approximately $361 million is attributable to losses and deductions related to PG&E NEG and its subsidiaries that were incorporated into PG&E Corporation's 2002 consolidated federal income tax return. It has been asserted that PG&E NEG has a direct interest in $361 million of the funds received by PG&E Corpo ration at a minimum. PG&E Corporation denies that any tax sharing agreement, whether implied or express, ever existed and denies that it has any obligation to compensate PG&E NEG for the incorporation of its or its subsidiaries' losses and deductions into PG&E Corporation's consolidated federal tax returns, as required under the Internal Revenue Code. Nevertheless, any adjudication of PG&E NEG's claim and any use or disposition of such funds will be subject to resolution in PG&E NEG's bankruptcy proceeding. Consequently, until the dispute is resolved in the Chapter 11 proceeding, PG&E Corporation is treating $361 million of the amount received by PG&E Corporation as restricted cash.

PG&E Corporation does not expect that the outcome of this matter will have a material adverse effect on its results of operations. As described in Note 3 above, effective July 8, 2003, PG&E Corporation no longer will consolidate PG&E NEG's financial results and will begin accounting for its investment in PG&E NEG using the cost method.

~~As further discussed above,~~In addition, PG&E Corporation has guaranteed the Utility's reimbursement obligation associated with certain surety bonds and the Utility's ~~obligation~~obligations to pay workers' compensation claims.

The Utility may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under the Comprehensive Environmental Response Compensation and Liability Act and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if the Utility 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 likely clean-up costs can be reasonably estimated. The Utility reviews its remediation liability on a quarterly basis for each site that may be exposed to remediation responsibilities. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure using (1) current technology, (2) enacted laws and regulations, (3) experience gained at similar sites, and (4) the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the lower end of this range.

The Utility had an undiscounted environmental remediation liability of ~~$286~~$302 million at ~~March 31,~~June 30, 2003, and $331 million at December 31, 2002. During the first ~~quarter,~~half of the year, the liability was reduced by ~~$45~~$29 million primarily due to a reassessment of the estimated cost of remediation. The ~~$286~~$302 million accrued at ~~March 31,~~June 30, 2003, includes (1) ~~$103~~$105 million related to the pre-closing remediation liability associated with divested generation facilities, and (2) ~~$183~~$197 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, compressor stations, and manufactured gas plant sites that are either owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former gas ~~gathering sites, and compressor stations.~~plant sites. Of the ~~$286~~$302 million environmental remediation liability, the Utility has recovered ~~$153~~$155 million through rates charged to its customers, and expects to recover ~~approximately $96~~approximatel y $93 million of the balance in future rates. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refunds to ratepayers. The Utility also is recovering its costs from insurance carriers and from other third parties whenever it is possible.

The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. ~~A change in the~~The estimate ~~may occur in the near term due to uncertainty concerning~~depends on a number of uncertainties, including the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper limit of the range using assumptions least favorable to the Utility, which is based upon a range of reasonably possible outcomes. The Utility's future costs could increase to as much as ~~$396~~$418 million if (1) the other potentially responsible parties are not financially able to contribute to these costs, (2) the extent of contamination or necessary remediation is greater than anticipated, or (3) the Utility is found to be responsible for clean-up costs at additional sites.

On June 28, 2001, the Bankruptcy Court authorized the Utility to continue its hazardous waste remediation program and to expend (1) up to $22 million in hazardous substance remediation programs and procedures in each calendar year in which the Chapter 11 case is pending, and (2) any additional amounts in emergency situations involving post-petition releases or threatened releases of hazardous substances subject to the Bankruptcy Court's specific approval.

The California Attorney General, on behalf of various state environmental agencies, filed claims in the Utility's ~~bankruptcy~~Chapter 11 proceeding for environmental remediation at numerous sites totaling approximately $770 million. For most ~~if not all~~ of these sites, remediation is ongoing in the normal course of business or the Utility is in the process of remediation in cooperation with the relevant agencies and other parties responsible for contributing to the ~~clean-up in the normal course of business.~~clean-up. Since the Utility's proposed plan of reorganization provides that the Utility intends to respond to these types of claims in the regular course of business, and since the Utility has not argued that the ~~bankruptcy~~Chapter 11 proceeding relieves the Utility of its obligations to respond to valid environmental remediation orders, the Utility believes the state's claims seeking specific cash recoveries are ~~invalid.~~unenforceable.

Moss Landing - In December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that it had identified a cleaning procedure used at the plant that released heated water and organic debris from the intake, and that this procedure is not specified in the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. A settlement has been reached with the Central Coast Board, under which the Utility would pay a total of $5 million to be used for environmental projects. No civil penalties would be paid under the settlement. The Central Coast Board voted to accept the settlement in December 2002, and the Utility has obtained authorization from the Bankruptcy Court to enter into the final settlement agreement. The parties have signed the settlement agreement, which was incorporated into a consent decree entered in the California Superior Court on May 9, 2003. The California Attorney General has filed a claim in the Utility's Chapter 11 case to preserve the Central Coast Board's claim. The Utility currently is seeking withdrawal of this claim.

The Utility believes the ultimate outcome of this matter will not have a material impact on its consolidated financial position of results of operations.

Diablo Canyon - The Utility's Diablo Canyon employs a "once-through" cooling water system, which is regulated under an 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 alleging that, although the temperature limit has never been exceeded, Diablo Canyon's discharge was not protective of beneficial uses.

In May 2000, USGenNE, an indirect subsidiary of PG&E NEG, received an Information Request from the U.S. Environmental Protection Agency (EPA), pursuant to Section 114 of the Federal Clean Air Act (CAA). The Information Request asked USGenNE to provide certain information relative to the compliance of its Brayton Point and Salem Harbor plants with the CAA. No enforcement action has been brought by the EPA to date. USGenNE has had preliminary discussions with the EPA to explore a potential settlement of this matter. ~~Management believes that it~~It is not possible to predict at this point whether any such settlement will occur or, in the absence of a settlement, the likelihood of whether the EPA will bring an enforcement action.

As a result of the EPA Information Request and environmental regulatory initiatives by the Commonwealth of Massachusetts, USGenNE is exploring ways to achieve significant reductions of sulfur dioxide (SO₂) and nitrogen oxide (No_x) emissions. Additional requirements for the control of mercury and carbon dioxide emissions also will be forthcoming as part of these regulatory initiatives. Management believes that USGenNE would meet these requirements through installation of controls at the Brayton Point and Salem Harbor plants, and estimates that capital expenditures on these environmental projects could approximate ~~$376~~$426 million over the next four years. These estimates are currently under review and it is possible that actual expenditures may be higher. Based on an emission control plan filed for Brayton Point under the regulations implementing these initiatives, the Massachusetts Department of Environmental Protection (DEP) ruled that Brayton Point is required to meet the newer, ~~more~~mo re stringent emission limitations ~~fo r sulfur dioxide~~for SO₂ and ~~nitrogen oxide~~No_x by 2006. ~~In April 2002,~~

On June 19, 2003, USGenNE, ~~filed with~~ the DEP, ~~a revised plan for~~the City of Salem, Harbor that it believes meets the DEP requirements for the 2006 compliance date. However, on June 7, 2002, the DEP ruled that Salem Harbor must satisfy these limitations by 2004. USGenNE has since filedand various environmental/citizen groups entered into an Administrative Consent Order (ACO) to resolve a number of administrative appeals ~~challenging this decision and unless and until~~regarding matters related to the ~~decision is reversed,~~Massachusetts air regulations for the ~~compliance date for~~ Salem Harbor ~~remains October 2004.~~Station. The ACO's terms will constitute compliance with the NO_x and SO₂ provisions of the regulations. The ACO describes generally how USGenNE will comply with these regulations and takes into account the need for reliable electricity supplies, the financial uncertainties surrounding USGenNE, the fiscal uncertainties of the City of Salem, and the ~~DEP recently~~economic risks to the workers at the facility. USGenNE has represented to the parties that USGenNE does not have ~~agreed~~the ability to finance the capital improvements it has proposed to achieve compliance, and that, as a result, such funding must be provided by public sources unaffiliated with USGenNE. The ACO also requires USGenNE to implement certain near-term pollutio n control measures. The ACO was submitted to the ALJ, together with a motion to enter ~~into negotiations concerning Salem Harbor's compliance schedule with~~to ACO as a final resolution of the DEP regulation, in an attempt to develop a schedule that USGenNE could meet, assuming that financing and all other necessary approvals are in place. USGenNE will not be able to operate Salem Harbor unless it is in compliance with these emission limitations. PG&E NEG believes that it is impossible to meet the October 2004 deadline. Therefore, it may not be able to operate the facility after that deadline. USGenNE and t he DEP recently have agreed to enter into negotiations concerning a Salem Harbor compliance schedule with the DEP regulation on a schedule that USGenNE could meet, assuming that financing and all other necessary approvals are in place.

Various aspects of the DEP's regulations allow for public participation in the process through which the DEP determines whether the 2004 or 2006 deadline applies and approves the specific activities that USGenNE will undertake to meet the new regulations. A number of local environmental groups are now participants in this process.

The EPA is required under the CAA to establish new regulations for controlling hazardous air pollutants from combustion turbines and reciprocating internal combustion engines. Although the EPA has yet to propose the regulations, the CAA required that they be promulgated by November 2000. Another provision in the CAA requires companies to submit case-by-case Maximum Achievable Control Technology (MACT) determinations for individual plants if the EPA fails to finalize regulations within 18 months past the deadline. The EPA has extended this deadline through previous rulemakings. In late 2002, the EPA proposed a rule that would require the case-by-case MACT applications to be submitted by October 30, 2003, if the EPA has not promulgated a MACT rule as of that date. The EPA intends to finalize the MACT regulations before this date, thus eliminating the need for the plant-specific permits. PG&E NEG will not be able to accurately quantify the economic impact of the future regulations until more detail s are available through the rulemaking process.

PG&E NEG's existing power plants are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE (Salem Harbor, Manchester Street, and Brayton Point) are operating pursuant to ~~National Pollutant Discharge Elimination System (NPDES)~~NPDES permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and all three facilities are continuing to operate under existing terms and conditions until new permits are issued. On July 22, 2002, the EPA and the DEP issued a draft NPDES permit for Brayton Point that, among other things, substantially limits the discharge of heat by Brayton Point into Mount Hope Bay.

Based on its initial review of the draft permit, USGenNE believes that the draft permit is excessively stringent. It is estimated that USGenNE's cost to comply with the new permit conditions could be as much as $248 million through 2006, but this is a preliminary estimate. There are various administrative and judicial proceedings that must be completed before the draft NPDES permit for Brayton Point becomes final, and these proceedings are not expected to be completed during 2003. In addition, the EPA, as well as local environmental groups, previously expressed concern that the metal vanadium is not addressed at Brayton Point or Salem Harbor under the terms of the old NPDES permits. ~~Based upon the lack of an identified control technology, USGenNE believes it is unlikely that the EPA will require that vanadium be addressed pursuant to a NPDES permit.~~ However, if the EPA does insist on including vanadium in the NPDES permit, USGenNE may have to spend a significant amount of cost to comply with such a provision. In addition, it is possible that the new permits for Salem Harbor and Manchester Street also may contain more stringent limitations than prior permits and that the cost to comply with the new permit conditions could be greater ~~tha n~~than the current estimate of $4 million. Lastly, the issuance of any final NPDES permits may be affected by the EPA's proposed regulations under Section 316(b) of the Clean Water ~~Act.~~

On March 27, 2002, the Rhode Island Attorney General notified USGenNE of his belief that Brayton Point "is in violation of applicable statutory and regulatory provisions governing its ~~operations,~~operations..." including "protections accorded by common law" respecting discharges from the facility into Mount Hope Bay. He stated that he intends to seek judicial relief "to abate these environmental law violations and to recover ~~damages"~~damages..." within the next 30 days. PG&E NEG believes that Brayton Point is in full compliance with all applicable permits, laws, and regulations. The complaint has not yet been filed or served. In early May 2002, the Rhode Island Attorney General stated that he did not plan to file the action until the EPA issues a draft Clean Water Act NPDES permit for Brayton Point. The EPA issued this draft permit on July 22, 2002, and the Rhode Island Attorney General has since stated he has no intention of pursuing this matter until he reviews USGenNE's response to the draft permit which was ~~submitted~~submi tted on October 4, 2002. ~~Management~~It is ~~unable to predict~~uncertain whether hethe Rhode Island Attorney General will pursue this matter and, if he does, the extent to which it will have a material adverse effect on PG&E NEG's financial condition or results of operations.

On April 9, 2002, the EPA proposed regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations would affect existing power generation facilities using over 50 million gallons per day typically including some form of "once-through" cooling. Brayton Point, Salem Harbor, and Manchester Street are among an estimated 539 plants nationwide that would be affected by this rulemaking. The proposed rule calls for a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. The final regulations are scheduled to be promulgated in February 2004. The extent to which they may require additional capital investment will depend on the timing of the NPDES permit proceedings for the affected facilities.

During April 2000, an environmental group served USGenNE and other PG&E NEG subsidiaries with a notice of its intent to file a citizen's suit under the Resource Conservation Recovery Act. In September 2000, PG&E NEG signed a series of agreements with the DEP and the environmental group to resolve these matters that require PG&E NEG to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities. PG&E NEG began the activities during 2000 and is expected to complete them in 2003. PG&E NEG incurred expenditures related to these agreements of ~~$5.4~~$4.7 million in ~~2000,~~2002, $2.6 million in 2001, and ~~$4.7~~$5.7 million in ~~2002.~~2000. In addition to the costs previously incurred, PG&E NEG maintains a reserve in the amount of $6$5.4 million relating to its estimate of the remaining expenditures to fulfill its obligations under these agreements. PG&E NEG has deferred costs associated with capital expenditures and has set up a receivable account for ~~amounts~~amount s it believes are probable of recovery from insurance ~~proceeds.~~

PG&E NEG believes that it may be required to spend up to approximately ~~$636~~$678 million, excluding insurance proceeds, through 2008 for environmental compliance to continue operating these facilities. This amount may change, however, and the timing of any necessary capital expenditures could be accelerated in the event of a change in environmental regulations or the commencement of any enforcement proceeding against PG&E NEG. PG&E NEG has not made any commitments to spend these amounts. In the event PG&E NEG does not spend or is unable to spend because of liquidity constraints amounts needed in order to comply with these requirements, PG&E NEG may not be able to continue to operate one or all of these facilities.

Global climate change is a significant environmental issue that is likely to require sustained global action and investment over many decades. The Utility and PG&E NEG ~~has~~have been engaged on the climate change issue for several years and isare working with others on developing appropriate public policy responses to this challenge. The Utility and PG&E NEG have continuously ~~assesses~~assessed the financial and operational implications of this issue; however, the outcome and timing of these initiatives are uncertain.

There are six greenhouse gases. The Utility and PG&E NEG ~~emits~~emit varying quantities of ~~six~~these greenhouse gases, including carbon dioxide and methane, in the course of ~~its~~their operations. Depending on the ultimate regulatory regime put into place for greenhouse gases, the Utility's or PG&E NEG's operations, cash flows and financial condition could be adversely affected. Given the uncertainty of the regulatory regime, it is not possible to predict the extent to which climate change regulation will have a material adverse effect on the Utility's or PG&E NEG's financial condition or ~~results~~result of operations.

The Utility and PG&E NEG are taking numerous steps to manage the potential risks associated with the eventual regulation of greenhouse gases, including but not limited to preparing inventories of greenhouse gas emissions, voluntarily reporting on these emissions through a variety of state and federal programs, engaging in demand side management programs that prevent greenhouse gas emissions, and supporting market-based solutions to the climate change challenge.

In accordance with SFAS No. 5, "Accounting for Contingencies," PG&E Corporation makes a provision for a liability when it is both 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 and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular case.

The provision for legal matters is included in PG&E Corporation's and the Utility's Other Noncurrent Liabilities in the Consolidated Balance Sheets, and totaled $219 million at June 30, 2003, and $202 million at December 31, 2002.

In the normal course of business, PG&E Corporation, the Utility, and PG&E NEG are named as parties in a number of claims and lawsuits. The most significant of these are discussed below. The Utility's Chapter 11 ~~bankruptcy~~ filing on April 6, 2001, discussed in Note 2, ~~of the Notes to the Consolidated Financial Statements,~~ automatically stayed the litigation described below against the Utility, except as otherwise noted.

There are 1514 civil suits pending against the Utility in several California state courts. One of these suits also names PG&E Corporation as a defendant. ~~One additional civil suit,~~~~Kearney v. Pacific Gas and Electric Company~~~~, was filed against the Utility and PG&E Corporation after the Utility's bankruptcy filing and was dismissed without prejudice while the~~Currently, there are approximately 1,200 plaintiffs ~~sought the right to file and pursue late claims~~ in the ~~Bankruptcy Court. In the~~~~Kearney~~ ~~case,~~chromium litigation cases. Approximately 1,260 individuals have filed proofs of claims with the Bankruptcy Court, ~~ruled~~most of whom are plaintiffs in the 14 chromium litigation cases. Approximately 1,035 of these claimants have filed proofs of claim requesting an approximate aggregate amount of $580 million and approximately another 225 claimants have filed claims for an "unknown amount."

In general, plaintiffs and claimants allege that the six adult plaintiffs could not file untimely bankruptcy claims against the Utility. The court also ruled that the 24 minor plaintiffs could file untimely bankruptcy claims against the Utility. The suits allege personal injuries, wrongful death, and loss of consortium and seek compensatory and punitive damages based on claims arising from alleged exposure to chromium inat or near the ~~vicinity of the~~ Utility's ~~gas~~ compressor stations at Hinkley and Kettleman, California, and the area of California ~~nea r~~near Topock, ~~Arizona. Currently, there are approximately 1,200 plaintiffs in~~Arizona, caused personal injuries, wrongful death, or other injury and seek related damages. The Bankruptcy Court has granted certain claimants' motion for relief from stay so that the ~~chromium litigation cases.~~state court lawsuits pending before the Utility's Chapter 11 filing can proceed.

The Utility is responding to the suits in which it has been served and is asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including statute of limitations, exclusivity of workers' compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged.

Approximately 1,260 individuals have filed proofs of claims with the Bankruptcy Court (most are plaintiffs in the 15 cases) alleging that exposure to chromium in soil, air, or water at or near the Utility's compressor stations at Hinkley and Kettleman, California, and the area of California near Topock, Arizona, caused personal injuries, wrongful death, or related damages. Approximately 1,035 of these claimants have filed proofs of claims requesting an approximate aggregate amount of $580 million and approximately another 225 claimants have filed claims for an "unknown amount." On November 14, 2001, theThe Utility filed objections to these claims and requested the Bankruptcy Court to transfer the chromium claims to the federal District Court. On January 8, 2002, the Bankruptcy Court denied the Utility's request to transfer the chromium claims and granted certain claimants' motion for relief from stay so that the state court lawsuits pending before the Utility filed its bankruptcy petition ca n proceed. Orders granting relief from stay have been entered.

~~As of April 6, 2001, the Utility had~~has filed 13 summary judgment motions challenging the claims of the trial test plaintiffs and had completed discovery of plaintiffs' experts. Plaintiffs' discovery of the Utility's experts was underway. Plaintiffs currently are completing discovery of the Utility's experts and of related issues, and four of the 13 summary judgment motions are scheduled for hearing in 2003. At a status conference on March 17, 2003, the Los Angeles Superior Court scheduled a trial of ~~eighteen~~18 test cases to commence in March 2004.

The Utility has recorded a 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 at ~~March 31,~~June 30, 2003, 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.

This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Grynberg (called a relator in the parlance of the False Claims Act) on behalf of the United States of America, against more than 330 defendants, including the Utility and PG&E GTN. The cases were consolidated for pretrial purposes in the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998.

Under procedures established by the False Claims Act, the United States, acting through the Department of Justice (DOJ), is given an opportunity to investigate the allegations and to intervene in the case and take over its prosecution if it chooses to do so. In April 1999, the U.S. DOJ declined to intervene in any of the cases.

The complaints allege that the various defendants (most of which are pipeline companies or their affiliates) incorrectly measured the volume and heat content of natural gas produced from federal or Indian leases. As a result, it is alleged that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases. The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties, and expenses associated with the litigation.

The relator has filed a claim in the Utility's ~~bankruptcy~~Chapter 11 case for $2.5 billion, $2 billion of which is based upon the plaintiff's calculation of penalties sought against the Utility.

PG&E Corporation and the Utility believe the allegations to be without merit and intend to present a vigorous defense. PG&E Corporation and the Utility believe that the ultimate outcome of the litigation will not have a material adverse effect on their financial condition or results of operations.

~~On April 16, 2001,~~This matter involves a second amended complaint that was filed against PG&E Corporation and ~~the Utility~~an executive officer of PG&E Corporation on February 4, 2002, in the U.S. District Court for the Central District of California. The Utility subsequently was dismissed, due to its Chapter 11 bankruptcy filing. By order entered on or about May 31, 2001, the case was transferred to the U.S. District Court for the Northern District of California, (District Court). On August 9, 2001, the plaintiff filed a first amended complaint in the District Court. An executive officer of PG&E Corporation also has been named as a defendant. The first amended complaint, purportedly brought on behalf of all persons who purchased PG&E Corporation common stock or certain shares of the Utility's preferred stock between July 20, 2000, and April 9, ~~2001, claimed~~2001. In January 2002, the District Court dismissed the plaintiffs' first amended complaint. The first and second amended complaints alleged that the defendants caused PG&E Corporation's Consolidated Financial Statements for the second and third quarters of 2000 to be materially misleading in violation of federal securities laws as a result ~~o f~~of recording as a deferred cost and capitalizing as a regulatory asset the under-collections that resulted when escalating wholesale energy prices caused the Utility to pay far more to purchase electricity than it was permitted to collect ~~from~~fro m customers. ~~On January 14, 2002,~~In the second amended complaint, the plaintiffs also repeated some of the allegations that appear in the California Attorney General's complaint discussed below. The plaintiffs sought an unspecified amount of compensatory damages, plus costs and attorneys' fees. In dismissing the first amended complaint, the District Court ~~granted the defendants' motion to dismiss the plaintiffs' first amended complaint, finding~~found that the complaint failed to state a claim in light of the public disclosures by PG&E Corporation, the Utility, and others regarding the under-collections, the risk that they might not be recoverable, the financial consequences of non-recovery, and other information from which analysts and investors could assess for themselves the probability of recovery.

On February 4, 2002, the plaintiffs filed a second amended complaint that, in addition to containing many of the same allegations as were in the first amended complaint, contains many of the same allegations that appear in the California Attorney General's complaint discussed below. The plaintiffs sought an unspecified amount of compensatory damages, plus costs and attorneys' fees. On March 11, 2002, the defendants filed a motion to dismiss the second amended complaint. After a hearing held onIn June ~~24,~~ 2002, the District Court ~~issued an order on June 25, 2002, granting the defendants' motion to dismiss~~dismissed the second amended ~~complaint. The dismissal is~~complaint with prejudice, prohibiting the plaintiffs from filing a further complaint. ~~On November 15, 2002,~~The plaintiffs' appeal of the ~~plaintiffs filed an appeal in~~dismissal was argued before the ~~United States~~U.S. Court of Appeals for the Ninth Circuit ~~advancing substantially~~on June 10, 2003. In July 2003, the ~~same arguments that~~Ninth Circuit court upheld the District Court's dismissal of the plaintiffs' second amended complaint. The plaintiffs have until October 29, 2003 to file a petition asking the U.S. Supreme Court ~~had rejected previously. The defendants filed~~to hear their ~~answer to~~appeal of the ~~appeal on January 2,~~Ninth Circuit's July 2003 ~~and expect that oral argument regarding the appeal will be heard in 2003.~~

PG&E Corporation believes the allegations to be without merit and ~~intends~~will continue vigorously responding to ~~present a vigorous defense.~~and defending against the litigation. PG&E Corporation believes that the ultimate outcome of the litigation will not have a material adverse effect on its financial condition or results of operations.

Order Instituting Investigation (OII) into Holding Company Activities ~~and Related Litigation~~

On April 3, 2001, the CPUC issued an OII into whether the California IOUs, 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 also will 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 str ucture. 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, prospective rules, or conditions, as appropriate.

On January 9, 2002, the CPUC issued an interim decision and order interpreting the "first priority condition" adopted in the CPUC's holding company decision. This condition requires that the capital requirements of the Utility, as determined to be necessary and prudent to meet the ~~Utility's~~utility's obligation to serve or to operate the ~~Utility~~utility in a prudent and efficient manner, be given first priority by the board of directors of the holding company. In the interim order, the CPUC stated, "the first priority condition does not preclude the requirement that the holding company infuse all types of capital into their respective utility subsidiaries where necessary to fulfill the Utility's obligation to serve." The three major California ~~investor-owned energy utilities~~IOUs and their parent holding companies had opposed the broader interpretation, first contained in a proposed decision released for comment on December 26, 2001, as being inconsistent with the prior 15 years' understanding of that ~~conditio n~~condition as applying more narrowly to a priority on capital needed for investment purposes. The CPUC also interpreted the first priority condition as prohibiting a holding company from (1) acquiring assets of its utility subsidiary for inadequate consideration, and (2) acquiring assets of its utility subsidiary at any price, if such acquisition would impair the utility's ability to fulfill its obligation to serve or to operate in a prudent and efficient manner. The utilities' applications for rehearing were denied on July 17, 2002.

In a related decision, the CPUC denied the motions filed by the California utility holding companies to dismiss the holding companies from the pending investigation on the basis that the CPUC lacks jurisdiction over the holding companies. However, in the interim decision interpreting the first priority condition discussed above, the CPUC separately dismissed PG&E Corporation (but no other utility holding company) as a respondent to the proceeding. In its written decision adopted on January 9, 2002, the CPUC stated that PG&E Corporation was being dismissed so that an appropriate legal forum could decide expeditiously whether adoption of the Utility's original proposed ~~Plan~~plan of ~~Reorganization~~reorganization would violate the first priority condition. The utilities' applications for rehearing were denied on July 17, 2002.

The holding ~~companies have filed~~companies' petitions for review of ~~both the CPUC's capital requirements and jurisdiction~~these CPUC decisions in several state appellate courts, and the utilities also have filed petitions for review of the capital requirements decision with the California appellate courts. The CPUC moved to consolidate all proceedings in the San Francisco state appellate court and requested that the court extend the deadline by which the CPUC must file its responses to the petitions for review until after the consolidation occurred. The CPUC's request for consolidation was granted and all of the petitions are ~~now~~pending before the First Appellate District in San Francisco, California.

The proposed settlement agreement in the Utility's Chapter 11 proceeding provides that on or as soon as practicable after the later of the effective date of the Settlement Plan or the date the CPUC decision approving the proposed settlement agreement is final and nonappealable, the Utility, PG&E Corporation, on the one hand, and the CPUC, on the other, will execute full mutual releases and dismissals with prejudice of certain claims, actions or regulatory proceedings, as specified in the settlement agreement, arising out of or related in any way to the energy crisis or the implementation of AB 1890, including the CPUC's investigation into past holding company actions during the energy crisis (but only as to past actions, not prospective matters).

PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. Neither the Utility nor PG&E Corporation, however, can predict what the outcome of the CPUC's investigation will be or whether the outcome will have a material adverse effect on their results of operations or financial condition.

Complaints Filed by the California Attorney General, City and County of San Francisco, and Cynthia Behr

On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against directors of the Utility, alleging that PG&E Corporation violated various conditions established by the CPUC in decisions approving the holding company formation, among other allegations. The Attorney General also alleged that the December 2000 and January and February 2001 ringfencing transactions by which PG&E Corporation subsidiaries complied with credit rating agency criteria to establish independent credit ratings violated the holding company conditions.

Among other allegations, the Attorney General alleged that, through the Utility's ~~bankruptcy~~Chapter 11 proceedings, PG&E Corporation and the Utility engaged in unlawful, unfair, and fraudulent business practices in alleged violation of California Business and Professions Code Section 17200 by seeking to implement the transactions contemplated in the original proposed ~~Plan~~plan of ~~Reorganization~~reorganization filed in the Utility's ~~bankruptcy~~Chapter 11 proceeding. The complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E Corporation from the Utility. In February 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Court to transfer the Attorney General's complaint to the Bankruptcy Court, as well as a motion to dismiss the lawsuit, or in the alternative, to stay the suit with the Bankruptcy Court. Subsequently, the Attorney General filed a motion to remand the action to state court. In June 2002, the Bankruptcy Court held that federal law preempted the Attorney General's ~~allegations~~all egations concerning PG&E Corporation's participation in the Utility's ~~bankruptcy~~Chapter 11 proceedings. The Bankruptcy Court directed the Attorney General to file an amended complaint omitting these allegations and remanded the amended complaint to the San Francisco Superior Court. Both parties ~~have~~ appealed the Bankruptcy Court's remand ~~order.~~order to the Northern District. The appeal and cross-appeal were argued before the Northern District on July 24, 2003, and the parties are ~~pending in the District Court.~~

On August 9, 2002, the California Attorney General filed its amended complaint in the San Francisco Superior Court, omitting the allegations concerning PG&E Corporation's participation in the Utility's ~~bankruptcy~~Chapter 11 proceedings. PG&E Corporation and the directors named in the complaint have filed a motion to strike certain allegations of the amended complaint. In February 2003, the court denied the motions to strike on the grounds that they were premature, and stated that it would defer making a judgment on the merits of the defendants' arguments until the factual context of the case is more fully developed. A status conference has been scheduled for ~~June 4,~~August 29, 2003.

~~The California Attorney General's case has been coordinated by the San Francisco Superior Court with the cases filed by the City and County of San Francisco and Cynthia Behr, both discussed below.~~

On February 11, 2002, a complaint entitledCity and County of San Francisco; People of the State of California v. PG&E Corporation, and Does 1-150, was filed in San Francisco Superior Court. The complaint contains some of the same allegations contained in the Attorney General's complaint, including allegations of unfair competition. In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation "took at least $5.2 billion from the Utility," and for unjust enrichment. The City seeks injunctive relief, the appointment of a receiver, payment to ratepayers, disgorgement, the imposition of a constructive trust, civil penalties, and costs of suit.

After removing the ~~city's~~City's action to the Bankruptcy Court in February 2002, PG&E Corporation filed a motion to dismiss the complaint. Subsequently, the City filed a motion to remand the action to state court. In June 2002, the Bankruptcy Court issued an Amended Order on Motion to Remand stating that the Bankruptcy Court retained jurisdiction over the causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by the City and County, but remanding the Section 17200 cause of action to state court. Both parties have appealed the Bankruptcy Court's remand ~~order.~~order to the Northern District. The appeal and cross-appeal were argued before the Northern District on July 24, 2003, and the parties are ~~pending in the District Court.~~

~~Following remand, PG&E Corporation brought~~waiting for a motion to strike. In February 2003, the court denied the motion to strike on the grounds that it was premature, and stated that it would defer making a judgment on the merits of the defendants' arguments until the factual context of the case is more fully developed.decision. A status conference has been scheduled for ~~June 4,~~August 29, 2003.

PG&E Corporation also moved to coordinate this case with the Section 17200 case brought by Cynthia Behr, which is discussed below. That motion was granted. Subsequently, the court coordinated the California Attorney General's case with the~~City and County of San Franciscoand~~~~Behr~~~~cases.~~

In addition, a third case, entitledCynthia Behr v. PG&E Corporation, et al., was filed on February 14, 2002, by a private plaintiff (who also has filed a claim ~~in bankruptcy)~~under Chapter 11) in Santa Clara Superior Court also alleging a violation of California Business and Professions Code Section 17200. The Behr complaint also names the directors of PG&E Corporation and the Utility as defendants. The allegations of the complaint are similar to the allegations contained in the Attorney General's complaint but also include allegations of conspiracy, fraudulent transfer, and violation of the California bulk sales laws. The plaintiff requests the same remedies as the Attorney General's case and in addition requests damages, attachment, and restraints upon the transfer of defendants' property. In March 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Court to transfer the complaint to the Bankruptcy Court. Subsequently, the plaintiff filed a motion to remand the action to state court. In its June 2002 ruling mentioned above as to the Attorney General's and the City's cases, the Bankruptcy Court retained jurisdiction over Behr's fraudulent transfer claim and bulk sales claim, finding them to belong to the Utility's estate. The Bankruptcy Court remanded Behr's Section 17200 claim to the Santa Clara Superior Court. Both parties have appealed the Bankruptcy Court's remand ~~order.~~order to the Northern District. The appeal and cross-appeal were argued before the Northern District on July 24, 2003, and the parties are ~~pending in the District Court.~~waiting for a decision.

~~Following remand, PG&E Corporation moved to have the~~~~Behr~~ ~~case coordinated with the City's case described above. That motion was granted, and the~~~~Behr~~ ~~case now is proceeding in San Francisco Superior Court. The~~~~Behr~~ ~~case also has been coordinated with the California Attorney General's case discussed above.~~

In ~~September 2002, the defendants asked~~April 2003, the San Francisco Superior Court ~~to dismiss Behr's complaint. In April 2003, the court denied the request as to Behr's Section 17200 claim, but granted the request with respect to~~dismissed Behr's civil conspiracy cause of action. A status conference has been scheduled for ~~June 4,~~August 29, 2003.

~~PG&E Corporation~~The California Attorney General's case has been coordinated by the San Francisco Superior Court with the cases filed by the City and ~~the Utility believe that they have complied with applicable statutes, CPUC decisions, rules,~~County of San Francisco and orders. Neither the Utility nor PG&E Corporation, however, can predict what the outcome of the CPUC's investigation will be or whether the outcome will have a material adverse effect on their results of operations or financial condition. Cynthia Behr.

PG&E Corporation believes that the allegations of the complaints are without merit and will vigorously respond to and defend against the litigation. PG&E Corporation cannot predict whether the outcome of the litigation will have a material adverse effect on its results of operations or financial condition.

On February 27, 2002, a group of 25 ratepayers filed a complaint against the Utility at the CPUC demanding an immediate reduction of approximately $0.035 per kWh in allegedly excessive electric rates and a refund of alleged recent over-collections in electric revenue since June 1, 2001. The complaint claims that electric rate surcharges adopted in the first quarter of 2001 due to the high cost of wholesale power (surcharges that increased the average electric rate by $0.04 per kWh) became excessive later in 2001. The only alleged over-collection amount calculated in the complaint is approximately $400 million during the last quarter of 2001. On April 2, 2002, the Utility filed an answer, arguing that the complaint should be denied and dismissed immediately as an impermissible collateral action and on the basis that the alleged facts, even if assumed to be true, do not establish that currently authorized electric rates are not reasonable. On May 10, 2002, the Utility filed a ~~mo tion~~motion to dismiss the complaint. The CPUC has not yet issued a decision. However, in November 2002, the CPUC issued a decision jointly in this complaint case and in the rate stabilization proceedings modifying the restrictions on use of revenues generated by the surcharges to permit the revenues to be used for the purpose of securing or restoring the Utility's reasonable financial health, as determined by the CPUC. After the CPUC determines when the AB 1890 rate freeze ended, the CPUC will determine the extent and disposition of the Utility's under-collected costs, if any, remaining at the end of the rate freeze. If the CPUC determines that the Utility recovered revenues in excess of its transition costs or in excess of other permitted uses, the CPUC may require the Utility to refund such excess revenues. If the CPUC requires the Utility to refund any of these revenues in the future, the Utility's earnings could be materially affected. Under the proposed settlement agreement in the Utility's Chapter 11 proceeding, the CPUC would acknowledge and agree that the headroom, surcharge and base revenues accrued or collected by the Utility through and including December 31, 2003, are the property of the Utility's Chapter 11 estate, have been or will be used for utility purposes, including to pay creditors in the Utility's Chapter 11 proceeding, have been included in the Utility's retail electric rates consistent with state and federal law and are not subject to refund.

Mitsubishi Power Systems, Inc. (MPS) has alleged a default under its contract for the sale and purchase of gas turbines and other equipment for failure to pay $14 million. PG&E NEG's subsidiary has disputed this default notice because the payments were not due until January and July 2003. MPS terminated the contract for this alleged default on November 21, 2002. Although PG&E NEG does not agree that MPS had the right to do so, neither PG&E NEG nor any of its affiliates intended to challenge the termination. On January 31, 2003, PG&E NEG paid $4.5 million of the $14 million.

On May 7, 2003, Mitsubishi Heavy Industries, Inc. (MHI) filed suit in the ~~United States~~U.S. District Court for the District of Maryland against PG&E NEG, PG&E National Energy Group, LLC (NEG LLC), and PG&E National Energy Group Construction Company, LLC ~~(Construction). The defendants have not yet been served.~~(NEG Construction), involving a turbine purchase agreement and related contracts. On or about July 21, 2003, PG&E NEG notified the District Court of the automatic stay of litigation imposed by the bankruptcy laws. In its complaint, MHI alleges damages totaling approximately $300 million under the turbine purchase agreement and related contracts. MHI's claims arise from a dispute between the parties to a turbine purchase agreement regarding payments allegedly past due from NEG Construction in respect of reservation fees ($9.5 million) and gas generator equipment manufacture ($30 million). MPS also requested that PG&E NEG cash collateralize its $75 million guarantee issued in connection with the turbine purchase agreement. PG&E NEG and ~~Construction~~NEG Con struction have maintained (and will maintain in defense of MHI's claims) that no amounts were or are due.

As a result of PG&E ~~Corporation cannot predict whether~~NEG's Chapter 11 filing, on August 5, 2003, the District Court entered an order staying the litigation. MHI has voluntarily dismissed, without prejudice, its claims against NEG LLC, and has opposed the District Court's stay order. NEG Construction intends to oppose MHI's response to the District Court's stay order.

The outcome of ~~the litigation will~~this matter is not expected to have a material adverse effect on ~~its~~PG&E Corporation's results of operations or financial condition.

~~In accordance with SFAS No. 5 "Accounting for Contingencies,"~~ Effective July 8, 2003, PG&E ~~Corporation makes a provision for a liability when it is both probable that a liability has been incurred and the amount of the loss can~~NEG's results will no longer be reasonably estimated. These provisions are reviewed quarterly and adjusted to reflect the impacts of negotiations, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular case.

~~The provision for legal matters is included in~~consolidated into PG&E Corporation's ~~and the Utility's Other Noncurrent Liabilities in the Consolidated Balance Sheets and totaled $200 million at March 31, 2003, and $202 million at December 31, 2002.~~financial results (see Note 1).

PG&E Corporation has identified three reportable operating segments based on similarities in the following characteristics:

The Utility is one reportable operating segment and the other two are part of PG&E NEG. These three reportable operating segments provide different products and services and are subject to different forms of regulation or jurisdictions.

Segment information for the three and six months ended ~~March 31,~~June 30, 2003, and 2002, was as follows:

On May 28, 2003, two of the Utility's unions ratified new contracts, which provide for, among other items, an increase in benefits provided under the Utility's defined benefit pension plan (Retirement Plan). As a result of the ratifications, the Utility remeasured the assets and liabilities of the Retirement Plan at May 28, 2003. In connection with the remeasurement, which reflected a reduction in the current discount rate from the Retirement Plan's previous actuarial valuation, the Utility recorded a minimum pension obligation of $478 million, the amount by which the accumulated benefit obligation exceeded the fair market value of plan assets, and reduced its pension asset from $887 million to $353 million. The Utility has previously recognized a regulatory liability for timing differences between recognition of pension costs in accordance with GAAP and ratemaking purposes. As a result of the remeasurement, the Utility has reduced this regulatory liability by $911 million. The remaining amount of $6 0 million, net of income tax benefit of $41 million, has been recorded as a component of shareholders' equity in OCI in the Consolidated Balance Sheets. The charge to OCI does not affect earnings or cash flow, and could be reversed in future periods if the fair value of plan assets exceeds the accumulated benefit obligation. The Utility's defined benefit pension plan currently exceeds the minimum funding requirements of the Employee Retirement Income Security Act of 1974.

On July 2, 2003, PG&E Corporation completed a private placement of $600 million of 6-7/8 percent Senior Secured Notes due 2008 (Notes). The Notes are secured by a pledge of approximately 94 percent of the outstanding common stock of the Utility and are senior to all existing and future subordinated indebtedness, including PG&E Corporation's outstanding $280 million 9.50 percent Convertible Subordinated Notes.

The indenture, dated as of July 2, 2003, does not contain restrictions on the ability of the Utility and PG&E NEG to incur debt.

The net proceeds of the offering of approximately $583 million, together with cash on hand, were used to repay approximately $739 million under PG&E Corporation's existing credit agreement. A pre-tax loss of approximately $89 million will be recorded in the third quarter of 2003 to reflect the write-off to interest expense of unamortized loan fees, loan discount and prepayment fees. The payment resulted in the termination of PG&E Corporation's existing credit agreement and the release of liens on PG&E Corporation's shares of PG&E NEG, as well as the prior lien on approximately 94 percent of the outstanding common stock of the Utility.

Interest on the Notes accrues at the rate of 6-7/8 percent per annum and is payable semi-annually in arrears on January 15 and July 15, commencing January 15, 2004. The notes are redeemable at the option of PG&E Corporation at any time, at redemption prices described in the indenture. PG&E Corporation is not required to make mandatory redemption or sinking fund payments with respect to the Notes. However, under certain circumstances involving a change of control, spin-off, or reorganization event, as described in the indenture, PG&E Corporation is required to offer to purchase the Notes.

ITEM 2: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

PG&E Corporation is ~~an energy-based~~a holding company headquartered in San Francisco, ~~California, that conducts~~California: its ~~business through two~~ principal ~~subsidiaries:~~subsidiary, the Pacific Gas and Electric Company ~~(the Utility)~~(Utility), is an operating public utility engaged primarily in the business of providing electricity, natural gas distribution, and transmission services throughout most of Northern and Central ~~California, and PG&E National Energy Group, Inc. (PG&E NEG), a company currently engaged in power generation and natural gas transmission.~~California.

~~The~~On April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the ~~United States~~federal Bankruptcy Code (Bankruptcy Code) in the ~~U. S.~~U.S. Bankruptcy Court for the Northern District of California ~~(Bankruptcy Court) on April 6, 2001.~~(referred to as the "Bankruptcy Court" in this report's discussion of the Utility's Chapter 11 filing). Pursuant to Chapter 11 of the 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)~~ of Financial Condition and Results of Operations (MD&A) and in Note 2 of the Notes to the Consolidated Financial Statements.

PG&E ~~NEG~~National Energy Group, Inc. (PG&E NEG), another subsidiary of PG&E Corporation, is a company with subsidiaries currently engaged in electricity generation and ~~its principal subsidiaries include:~~

~~As a result of the sustained downturn~~natural gas transmission in the power industry, PG&E NEG and its affiliates have experienced a financial downturn, which caused the major credit rating agencies to downgrade PG&E NEG's and its affiliates' credit ratings to below investment grade. PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling $2.7 billion, but this debt is non-recourse to PG&E NEG. At March 31,United States of America. On July 8, 2003, ~~PG&E NEG had total liabilities in excess of total assets of approximately $1.4 billion dollars.~~

PG&E NEG, its subsidiaries, and their lenders have been engaged in discussions to restructure PG&E NEG's and its subsidiaries' debt obligations and other commitments since October 2002. No agreement has been reached yet and there can be no assurance that an agreement will be reached. Any restructuring agreement that may be reached would be implemented through a reorganization proceeding under Chapter 11 of the Bankruptcy Code. Although PG&E NEG and its subsidiaries are continuing their efforts to maximize cash and reduce liabilities, such efforts are not expected to restore the financial condition of PG&E NEG and its subsidiaries. Absent a negotiated agreement, the lenders may exercise their default remedies or force PG&E NEG and certain of its subsidiaries ~~into an involuntary proceeding~~filed voluntary petitions for relief under Chapter 11 of the Bankruptcy ~~Code. Notwithstanding~~Code in the ~~status~~U.S. Bankruptcy Court for the District of ~~current negotiations,~~Maryland, Greenbelt Division (referred to as the "Bankruptcy Court" in this report's discussion of PG&E NEG's Chapter 11 filing). Pursuant to Chapter 11 of the Bankruptcy Code, PG&E NEG and ~~certain~~those subsidiaries retain control of ~~its subsidiaries also may elect~~their assets and are authorized to ~~voluntarily seek protection under~~operate their businesses as debtors-in-possession while they are subject to the jurisdiction of the Bankruptcy ~~Codeas early as the second quarter of 2003. Although PG&E Corporation continues to provide assistance to~~Court. The factors causing PG&E NEG ~~its subsidiaries and its lenders in their negotiations, management does not expect the outcome of any bankruptcy proceeding involving PG&E NEG or any of its subsidiaries~~ to ~~have a material adverse effect on the financial condition of PG&E Corporation or the Utility.~~

~~The factors affecting PG&E NEG's business and causing these defaults as well as the principal actions being taken by PG&E NEG~~take this action are discussed ~~later~~ in this MD&A and in Note 3 of the Notes to the Consolidated Financial Statements.

During the fourth quarter of 2002, PG&E NEG and certain subsidiaries agreed to sell or sold certain assets, abandoned other assets, and significantly reduced energy trading operations. As a result, PG&E NEG incurred significant charges in the fourth quarter of 2002. As a result, PG&E NEG expects to incur substantial charges to earnings in 2003 as it continues to restructure its operations.

These segments were determined based on similarities in the following characteristics:

These three reportable operating segments provide different products and services and are subject to different forms of ~~regulations~~regulation or ~~jurisdictions.~~jurisdiction. Financial information about each reportable operating segment is provided in this MD&A and in Note 7 of the Notes to the Consolidated Financial Statements.

This MD&A explains the general financial condition and the results of operations of PG&E Corporation and its subsidiaries, including:

This combined Quarterly Report on Form 10-Q, including this MD&A, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on information currently available to management. These forward-looking statements are identified by words such as "estimates," "expects," "anticipates," "plans," "believes," "could," "should," "would," "may," 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 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 from historical results, include:

~~Recovery~~Outcome of ~~Under-Collected Power Procurement~~the Utility's Chapter 11 Case. PG&E Corporation's and ~~Transition Costs Previously Written Off. The extent to~~the Utility's future results of operations and financial conditions may be affected by the pace and outcome of the Utility's Chapter 11 case, which ~~the Utility is able to recover its under-collected power procurement and transition costs previously written off~~ depends ~~on many factors, including:~~upon:

~~Refundability of Amounts Previously Collected. Whether the Utility is required to refund to ratepayers amounts previously collected depends on many factors, including:~~

~~Outcome of the Utility's Bankruptcy Case. The pace and outcome of the Utility's bankruptcy case will be affected by:~~

Operating ~~Environment. The~~Environment.The amount of operating income and cash flows the Utility may record may be influenced by the following:

Legislative and Regulatory ~~Environment. PG~~Environment.PG&E Corporation's and the Utility's business may be impacted by:

~~Regulatory Proceedings and Investigations. PG&E Corporation's and the Utility's business may be affected by:~~

Pending ~~Legal Proceedings. PG~~Litigation and Regulatory Proceedings.PG&E Corporation's and the Utility's future results of operations and financial conditions may be affected by the ~~outcomes of:~~

~~Competition. PG~~Competition.PG&E Corporation's and the Utility's future results of operations and financial conditions may be affected by:

~~Environmental~~Accounting and ~~Nuclear Matters. PG~~Risk Management.PG&E Corporation's and the Utility's future results of operations and financial conditions may be affected ~~by:~~

~~Accounting and Risk Management. PG&E Corporation's and the Utility's future results of operations and financial conditions may be affected by:~~

~~Potential Bankruptcy Filing. The timing and manner in which bankruptcy proceedings involving~~ PG&E NEG ~~and certain of its subsidiaries commence will be affected by:~~

~~Efforts to Restructure Operations. PG&E NEG's future results of operations and financial condition will be affected by the success of its efforts to restructure its operations, including:~~

Current Conditions in the Energy Markets and the Economy. PG&E Corporation's future results of operations and financial condition will be affected by changes in the energy markets, changes in the general economy, wars, embargoes, financial markets, interest rates, other industry participant failures, the markets' perception of energy merchants and other factors.

~~Actions of PG&E NEG Counterparties.~~Chapter 11 Proceedings. PG&E Corporation's future results of operations and financial condition may be affected ~~by:~~

As the ultimate impact of these and other factors is uncertain, these and other factors may cause future earnings to differ materially from historical results or outcomes currently sought or expected.

~~During 2002, adverse changes in the electric power and gas utility industry and energy markets affected PG&E Corporation, the Utility, and PG&E NEG's business, including:~~

~~In 1998, the State~~PG&E NEG provided guarantees related to other obligations by PG&E NEG companies to counterparties for goods or services. PG&E NEG does not believe that it has significant exposure under these guarantees. The most significant of ~~California implemented electric industry restructuring and established a framework allowing generators and other electricity providers~~these guarantees relate to ~~charge market-based prices~~performance under certain construction contracts. These guarantees represent guarantees of subsidiary obligations for electricity sold on the wholesale market. The implementing legislation also established a retail electricity rate freeze and a plan for recovery of generation-related costs that were expected to be uneconomic under the new market framework. State regulatory action further strongly encouraged the Utility to sell a majority of its fossil fuel-fired generation facilities and made it economically unattractive to retain its remaining generation facilities. The resulting sales of generation facilities and the inability to entertransactions entered into long-term purchased power contracts in turn made the Utility more dependent on spot purchases from the newly deregulated wholesale electricity market. Beginning in June 2000, wholesale prices for electricity began to increase. Prices moderated somewhat in the ~~fall before increasing~~ordinary course of business. Some of the guarantees relate to ~~unprecedented levels in November 2000~~the construction or development of PG&E NEG's power plants and ~~later months. Since the Utility's retail rates were frozen, it financed the higher costs of wholesale electricity by issuing debt and drawing on its credit facilities.~~pipelines. These guarantees are described below.

~~In the beginning of 2001, the major credit rating agencies lowered their ratings~~PG&E NEG has issued guarantees to construction financing lenders for the ~~Utility~~performance of the contractors building the Harquahala and Covert generating projects for up to $555 million. Additionally, PG&E ~~Corporation~~NEG has issued $100 million of guarantees to ~~non-investment grade levels. Consequently,~~ the ~~Utility lost access~~construction contractor of the Harquahala and Covert projects to ~~its bank facilities and capital markets, and could no longer continue buying electricity to deliver to its customers.~~cover certain separate cost-sharing arrangements. As a result of the settlement of the Shaw Litigation, these guarantees have been terminated.

PG&E NEG has provided a $300 million guarantee to support a tolling agreement that a wholly owned subsidiary, Attala Energy Company, LLC, has entered into with another wholly owned subsidiary, Attala Generating.

The balance of the guarantees are for commitments undertaken by PG&E NEG or subsidiaries in the ordinary course of business for services such as facility and equipment leases, ash disposal rights, and surety bonds.

In addition, PG&E Corporation has guaranteed the Utility's ~~lack of creditworthiness and similar conditions at the other California IOUs, in January 2001 the California Legislature~~reimbursement obligation associated with certain surety bonds and the ~~Governor of California authorized the DWR~~Utility's obligations to begin purchasing electricity for the State of California. Until January 2003, the DWR purchased the electricity needed to cover the Utility's net open position (the amount of electricity needed by retail electric customers that cannot be met by utility-owned generation and electricity under contract to the Utility).pay workers' compensation claims.

The ~~Utility's inability~~Utility may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under the Comprehensive Environmental Response Compensation and Liability Act and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if the Utility did not deposit those substances on the site.

The Utility had an undiscounted environmental remediation liability of $302 million at June 30, 2003, and $331 million at December 31, 2002. During the first half of the year, the liability was reduced by $29 million primarily due to a reassessment of the estimated cost of remediation. The $302 million accrued at June 30, 2003, includes (1) $105 million related to the pre-closing remediation liability associated with divested generation facilities, and (2) $197 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, compressor stations, and manufactured gas plant sites that are either owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former gas plant sites. Of the $302 million environmental remediation liability, the Utility has recovered $155 million through rates charged to its customers, and expects to recover approximatel y $93 million of the balance in future rates. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refunds to ratepayers. The Utility also is recovering its ~~electric procurement~~ costs from ~~customers~~insurance carriers and from other third parties whenever it is possible.

The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. The estimate depends on a number of uncertainties, including the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper limit of the range using assumptions least favorable to the Utility, which is based upon a range of reasonably possible outcomes. The Utility's future costs could increase to as much as $418 million if (1) the other potentially responsible parties are not financially able to contribute to these costs, (2) the extent of contamination or necessary remediation is greater than anticipated, or (3) the Utility is found to be responsible for clean-up costs at additional sites.

The California Attorney General, on behalf of various state environmental agencies, filed claims in the Utility's Chapter 11 proceeding for environmental remediation at numerous sites totaling approximately $770 million. For most of these sites, remediation is ongoing in the normal course of business or the Utility is in the process of remediation in cooperation with the relevant agencies and other parties responsible for contributing to the clean-up. Since the Utility's proposed plan of reorganization provides that the Utility intends to respond to these types of claims in the regular course of business, and since the Utility has not argued that the Chapter 11 proceeding relieves the Utility of its obligations to respond to valid environmental remediation orders, the Utility believes the state's claims seeking specific cash recoveries are unenforceable.

The Utility believes the ultimate outcome of this matter will not have a material impact on its consolidated financial position of results of operations.

In October 2000, the Central Coast Board and the Utility reached a tentative settlement of this matter pursuant to which the Central Coast Board 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 $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the settlement. On May 5, 2003, the Bankruptcy Court authorized the Utility to sign the final settlement agreement. On June 17, 2003, the settlement was fully executed by the Utility, the Central Coast Board, and the Attorney General's Office. In order for the settlement to become effective, among other things, the Cen tral Coast Board must renew Diablo Canyon's NPDES permit. However, at its July 10, 2003, meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement accepted in March 2003 and the Central Coast Board requested its staff to develop additional information on possible mitigation measures.

The California Attorney General has filed a claim in the Utility's Chapter 11 proceeding on behalf of the Central Coast Board seeking unspecified penalties and other relief in connection with Diablo Canyon's operation of its cooling water system. The Utility is seeking withdrawal of this claim.

The Utility believes the ultimate outcome of this matter will not have a material impact on its consolidated financial position or results of operations.

In May 2000, USGenNE, an indirect subsidiary of PG&E NEG, received an Information Request from the U.S. Environmental Protection Agency (EPA), pursuant to Section 114 of the Federal Clean Air Act (CAA). The Information Request asked USGenNE to provide certain information relative to the compliance of its Brayton Point and Salem Harbor plants with the CAA. No enforcement action has been brought by the EPA to date. USGenNE has had preliminary discussions with the EPA to explore a potential settlement of this matter. It is not possible to predict at this point whether any such settlement will occur or, in the absence of a settlement, the likelihood of whether the EPA will bring an enforcement action.

As a result of the EPA Information Request and environmental regulatory initiatives by the Commonwealth of Massachusetts, USGenNE is exploring ways to achieve significant reductions of sulfur dioxide (SO₂) and nitrogen oxide (No_x) emissions. Additional requirements for the control of mercury and carbon dioxide emissions also will be forthcoming as part of these regulatory initiatives. Management believes that USGenNE would meet these requirements through installation of controls at the Brayton Point and Salem Harbor plants, and estimates that capital expenditures on these environmental projects could approximate $426 million over the next four years. These estimates are currently under review and it is possible that actual expenditures may be higher. Based on an emission control plan filed for Brayton Point under the regulations implementing these initiatives, the Massachusetts Department of Environmental Protection (DEP) ruled that Brayton Point is required to meet the newer, mo re stringent emission limitations for SO₂ and No_x by 2006.

On June 19, 2003, USGenNE, the DEP, the City of Salem, and various environmental/citizen groups entered into an Administrative Consent Order (ACO) to resolve a number of administrative appeals regarding matters related to the Massachusetts air regulations for the Salem Harbor Station. The ACO's terms will constitute compliance with the NO_x and SO₂ provisions of the regulations. The ACO describes generally how USGenNE will comply with these regulations and takes into account the need for reliable electricity supplies, the financial uncertainties surrounding USGenNE, the fiscal uncertainties of the City of Salem, and the economic risks to the workers at the facility. USGenNE has represented to the parties that USGenNE does not have the ability to finance the capital improvements it has proposed to achieve compliance, and that, as a result, such funding must be provided by public sources unaffiliated with USGenNE. The ACO also requires USGenNE to implement certain near-term pollutio n control measures. The ACO was submitted to the ALJ, together with a motion to enter to ACO as a final resolution of the two adjudicatory proceedings.

PG&E NEG's existing power plants are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE (Salem Harbor, Manchester Street, and Brayton Point) are operating pursuant to NPDES permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and all three facilities are continuing to operate under existing terms and conditions until new permits are issued. On July 22, 2002, the EPA and the DEP issued a draft NPDES permit for Brayton Point that, among other things, substantially limits the discharge of heat by Brayton Point into Mount Hope Bay.

Based on its initial review of the draft permit, USGenNE believes that the draft permit is excessively stringent. It is estimated that USGenNE's cost to comply with the new permit conditions could be as much as $248 million through 2006, but this is a preliminary estimate. There are various administrative and judicial proceedings that must be completed before the draft NPDES permit for Brayton Point becomes final, and these proceedings are not expected to be completed during 2003. In addition, the EPA, as well as local environmental groups, previously expressed concern that the metal vanadium is not addressed at Brayton Point or Salem Harbor under the terms of the old NPDES permits. However, if the EPA does insist on including vanadium in the NPDES permit, USGenNE may have to spend a significant amount of cost to comply with such a provision. In addition, it is possible that the new permits for Salem Harbor and Manchester Street also may contain more stringent limitations than prior permits and that the cost to comply with the new permit conditions could be greater than the current estimate of $4 million. Lastly, the issuance of any final NPDES permits may be affected by the EPA's proposed regulations under Section 316(b) of the Clean Water Act, as described below.

On March 27, 2002, the Rhode Island Attorney General notified USGenNE of his belief that Brayton Point "is in violation of applicable statutory and regulatory provisions governing its operations..." including "protections accorded by common law" respecting discharges from the facility into Mount Hope Bay. He stated that he intends to seek judicial relief "to abate these environmental law violations and to recover damages..." within the next 30 days. PG&E NEG believes that Brayton Point is in full compliance with all applicable permits, laws, and regulations. The complaint has not yet been filed or served. In early May 2002, the Rhode Island Attorney General stated that he did not plan to file the action until the EPA issues a draft Clean Water Act NPDES permit for Brayton Point. The EPA issued this draft permit on July 22, 2002, and the Rhode Island Attorney General has since stated he has no intention of pursuing this matter until he reviews USGenNE's response to the draft permit which was submi tted on October 4, 2002. It is uncertain whether the Rhode Island Attorney General will pursue this matter and, if he does, the extent to which it will have a material adverse effect on PG&E NEG's financial condition or results of operations.

During April 2000, an environmental group served USGenNE and other PG&E NEG subsidiaries with a notice of its intent to file a citizen's suit under the Resource Conservation Recovery Act. In September 2000, PG&E NEG signed a series of agreements with the DEP and the environmental group to resolve these matters that require PG&E NEG to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities. PG&E NEG began the activities during 2000 and is expected to complete them in 2003. PG&E NEG incurred expenditures related to these agreements of $4.7 million in 2002, $2.6 million in 2001, and $5.7 million in 2000. In addition to the costs previously incurred, PG&E NEG maintains a reserve in the amount of $5.4 million relating to its estimate of the remaining expenditures to fulfill its obligations under these agreements. PG&E NEG has deferred costs associated with capital expenditures and has set up a receivable account for amount s it believes are probable of recovery from insurance companies.

PG&E NEG believes that it may be required to spend up to approximately $678 million, excluding insurance proceeds, through 2008 for environmental compliance to continue operating these facilities. This amount may change, however, and the timing of any necessary capital expenditures could be accelerated in the event of a change in environmental regulations or the commencement of any enforcement proceeding against PG&E NEG. PG&E NEG has not made any commitments to spend these amounts. In the event PG&E NEG does not spend or is unable to spend because of liquidity constraints amounts needed in order to comply with these requirements, PG&E NEG may not be able to continue to operate one or all of these facilities.

Global climate change is a significant environmental issue that is likely to require sustained global action and investment over many decades. The Utility and PG&E NEG have been engaged on the climate change issue for several years and are working with others on developing appropriate public policy responses to this challenge. The Utility and PG&E NEG have continuously assessed the financial and operational implications of this issue; however, the outcome and timing of these initiatives are uncertain.

There are six greenhouse gases. The Utility and PG&E NEG emit varying quantities of these greenhouse gases, including carbon dioxide and methane, in the course of their operations. Depending on the ultimate regulatory regime put into place for greenhouse gases, the Utility's or PG&E NEG's operations, cash flows and financial condition could be adversely affected. Given the uncertainty of the regulatory regime, it is not possible to predict the extent to which climate change regulation will have a material adverse effect on the Utility's or PG&E NEG's financial condition or result of operations.

In the normal course of business, PG&E Corporation, the Utility, and PG&E NEG are named as parties in a number of claims and lawsuits. The most significant of these are discussed below. The Utility's Chapter 11 filing on April 6, 2001, discussed in Note 2, automatically stayed the litigation described below against the Utility, except as otherwise noted.

There are 14 civil suits pending against the Utility in several California state courts. One of these suits also names PG&E Corporation as a defendant. Currently, there are approximately 1,200 plaintiffs in the chromium litigation cases. Approximately 1,260 individuals have filed proofs of claims with the Bankruptcy Court, most of whom are plaintiffs in the 14 chromium litigation cases. Approximately 1,035 of these claimants have filed proofs of claim requesting an approximate aggregate amount of $580 million and approximately another 225 claimants have filed claims for an "unknown amount."

In general, plaintiffs and claimants allege that exposure to chromium at or near the Utility's compressor stations at Hinkley and Kettleman, California, and the area of California near Topock, Arizona, caused personal injuries, wrongful death, or other injury and seek related damages. The Bankruptcy Court has granted certain claimants' motion for relief from stay so that the state court lawsuits pending before the Utility's Chapter 11 filing can proceed.

The Utility has filed 13 summary judgment motions challenging the claims of the trial test plaintiffs and four of the 13 summary judgment motions are scheduled for hearing in 2003. At a status conference on March 17, 2003, the Los Angeles Superior Court scheduled a trial of 18 test cases to commence in March 2004.

The Utility has recorded a 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 at June 30, 2003, 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.

The relator has filed a claim in the Utility's Chapter 11 case for $2.5 billion, $2 billion of which is based upon the plaintiff's calculation of penalties sought against the Utility.

This matter involves a second amended complaint that was filed against PG&E Corporation and an executive officer of PG&E Corporation on February 4, 2002, in the U.S. District Court for the Northern District of California, purportedly brought on behalf of all persons who purchased PG&E Corporation common stock or certain shares of the Utility's preferred stock between July 20, 2000, and April 9, 2001. In January 2002, the District Court dismissed the plaintiffs' first amended complaint. The first and second amended complaints alleged that the defendants caused PG&E Corporation's Consolidated Financial Statements for the second and third quarters of 2000 to be materially misleading in violation of federal securities laws as a result of recording as a deferred cost and capitalizing as a regulatory asset the under-collections that resulted ~~in billions of dollars in defaulted debt and unpaid bills and~~when escalating wholesale energy prices caused the Utility to pay far more to purchase electricity than it was permitted to collect fro m customers. In the second amended complaint, the plaintiffs also repeated some of the allegations that appear in the California Attorney General's complaint discussed below. The plaintiffs sought an unspecified amount of compensatory damages, plus costs and attorneys' fees. In dismissing the first amended complaint, the District Court found that the complaint failed to state a claim in light of the public disclosures by PG&E Corporation, the Utility, and others regarding the under-collections, the risk that they might not be recoverable, the financial consequences of non-recovery, and other information from which analysts and investors could assess for themselves the probability of recovery.

In June 2002, the District Court dismissed the second amended complaint with prejudice, prohibiting the plaintiffs from filing a further complaint. The plaintiffs' appeal of the dismissal was argued before the U.S. Court of Appeals for the Ninth Circuit on June 10, 2003. In July 2003, the Ninth Circuit court upheld the District Court's dismissal of the plaintiffs' second amended complaint. The plaintiffs have until October 29, 2003 to file a petition asking the U.S. Supreme Court to hear their appeal of the Ninth Circuit's July 2003 decision.

PG&E Corporation believes the allegations to be without merit and will continue vigorously responding to and defending against the litigation. PG&E Corporation believes that the ultimate outcome of the litigation will not have a material adverse effect on its financial condition or results of operations.

On January 9, 2002, the CPUC issued an interim decision and order interpreting the "first priority condition" adopted in the CPUC's holding company decision. This condition requires that the capital requirements of the Utility, as determined to be necessary and prudent to meet the utility's obligation to serve or to operate the utility in a prudent and efficient manner, be given first priority by the board of directors of the holding company. In the interim order, the CPUC stated, "the first priority condition does not preclude the requirement that the holding company infuse all types of capital into their respective utility subsidiaries where necessary to fulfill the Utility's obligation to serve." The three major California IOUs and their parent holding companies had opposed the broader interpretation, first contained in a proposed decision released for comment on December 26, 2001, as being inconsistent with the prior 15 years' understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The CPUC also interpreted the first priority condition as prohibiting a holding company from (1) acquiring assets of its utility subsidiary for inadequate consideration, and (2) acquiring assets of its utility subsidiary at any price, if such acquisition would impair the utility's ability to fulfill its obligation to serve or to operate in a prudent and efficient manner. The utilities' applications for rehearing were denied on July 17, 2002.

In a related decision, the CPUC denied the motions filed by the California utility holding companies to dismiss the holding companies from the pending investigation on the basis that the CPUC lacks jurisdiction over the holding companies. However, in the interim decision interpreting the first priority condition discussed above, the CPUC separately dismissed PG&E Corporation (but no other utility holding company) as a respondent to the proceeding. In its written decision adopted on January 9, 2002, the CPUC stated that PG&E Corporation was being dismissed so that an appropriate legal forum could decide expeditiously whether adoption of the Utility's original proposed plan of reorganization would violate the first priority condition. The utilities' applications for rehearing were denied on July 17, 2002.

The holding companies' petitions for review of these CPUC decisions are pending before the First Appellate District in San Francisco, California.

Complaints Filed by the California Attorney General, City and County of San Francisco, and Cynthia Behr

Among other allegations, the Attorney General alleged that, through the Utility's Chapter 11 proceedings, PG&E Corporation and the Utility engaged in unlawful, unfair, and fraudulent business practices in alleged violation of California Business and Professions Code Section 17200 by seeking to implement the transactions contemplated in the original proposed plan of reorganization filed in the Utility's Chapter 11 proceeding. The complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E Corporation from the Utility. In February 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Court to transfer the Attorney General's complaint to the Bankruptcy Court, as well as a motion to dismiss the lawsuit, or in the alternative, to stay the suit with the Bankruptcy Court. Subsequently, the Attorney General filed a motion to remand the action to state court. In June 2002, the Bankruptcy Court held that federal law preempted the Attorney General's all egations concerning PG&E Corporation's participation in the Utility's Chapter 11 proceedings. The Bankruptcy Court directed the Attorney General to file an amended complaint omitting these allegations and remanded the amended complaint to the San Francisco Superior Court. Both parties appealed the Bankruptcy Court's remand order to the Northern District. The appeal and cross-appeal were argued before the Northern District on July 24, 2003, and the parties are waiting for a decision.

After removing the City's action to the Bankruptcy Court in February 2002, PG&E Corporation filed a motion to dismiss the complaint. Subsequently, the City filed a motion to remand the action to state court. In June 2002, the Bankruptcy Court issued an Amended Order on Motion to Remand stating that the Bankruptcy Court retained jurisdiction over the causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by the City and County, but remanding the Section 17200 cause of action to state court. Both parties have appealed the Bankruptcy Court's remand order to the Northern District. The appeal and cross-appeal were argued before the Northern District on July 24, 2003, and the parties are waiting for a decision. A status conference has been scheduled for August 29, 2003.

In addition, a third case, entitledCynthia Behr v. PG&E Corporation, et al., was filed on February 14, 2002, by a private plaintiff (who also has filed a claim under Chapter 11) in Santa Clara Superior Court also alleging a violation of California Business and Professions Code Section 17200. The Behr complaint also names the directors of PG&E Corporation and the Utility as defendants. The allegations of the complaint are similar to the allegations contained in the Attorney General's complaint but also include allegations of conspiracy, fraudulent transfer, and violation of the California bulk sales laws. The plaintiff requests the same remedies as the Attorney General's case and in addition requests damages, attachment, and restraints upon the transfer of defendants' property. In March 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Court to transfer the complaint to the Bankruptcy Court. Subsequently, the plaintiff filed a motion to remand the action to state court. In its June 2002 ruling mentioned above as to the Attorney General's and the City's cases, the Bankruptcy Court retained jurisdiction over Behr's fraudulent transfer claim and bulk sales claim, finding them to belong to the Utility's estate. The Bankruptcy Court remanded Behr's Section 17200 claim to the Santa Clara Superior Court. Both parties have appealed the Bankruptcy Court's remand order to the Northern District. The appeal and cross-appeal were argued before the Northern District on July 24, 2003, and the parties are waiting for a decision.

In April 2003, the San Francisco Superior Court dismissed Behr's civil conspiracy cause of action. A status conference has been scheduled for August 29, 2003.

The California Attorney General's case has been coordinated by the San Francisco Superior Court with the cases filed by the City and County of San Francisco and Cynthia Behr.

On February 27, 2002, a group of 25 ratepayers filed a complaint against the Utility at the CPUC demanding an immediate reduction of approximately $0.035 per kWh in allegedly excessive electric rates and a refund of alleged recent over-collections in electric revenue since June 1, 2001. The complaint claims that electric rate surcharges adopted in the first quarter of 2001 due to the high cost of wholesale power (surcharges that increased the average electric rate by $0.04 per kWh) became excessive later in 2001. The only alleged over-collection amount calculated in the complaint is approximately $400 million during the last quarter of 2001. On April 2, 2002, the Utility filed an answer, arguing that the complaint should be denied and dismissed immediately as an impermissible collateral action and on the basis that the alleged facts, even if assumed to be true, do not establish that currently authorized electric rates are not reasonable. On May 10, 2002, the Utility filed a motion to dismiss the complaint. The CPUC has not yet issued a decision. However, in November 2002, the CPUC issued a decision jointly in this complaint case and in the rate stabilization proceedings modifying the restrictions on use of revenues generated by the surcharges to permit the revenues to be used for the purpose of securing or restoring the Utility's reasonable financial health, as determined by the CPUC. After the CPUC determines when the AB 1890 rate freeze ended, the CPUC will determine the extent and disposition of the Utility's under-collected costs, if any, remaining at the end of the rate freeze. If the CPUC determines that the Utility recovered revenues in excess of its transition costs or in excess of other permitted uses, the CPUC may require the Utility to refund such excess revenues. If the CPUC requires the Utility to refund any of these revenues in the future, the Utility's earnings could be materially affected. Under the proposed settlement agreement in the Utility's Chapter 11 proceeding, the CPUC would acknowledge and agree that the headroom, surcharge and base revenues accrued or collected by the Utility through and including December 31, 2003, are the property of the Utility's Chapter 11 estate, have been or will be used for utility purposes, including to pay creditors in the Utility's Chapter 11 proceeding, have been included in the Utility's retail electric rates consistent with state and federal law and are not subject to refund.

On May 7, 2003, Mitsubishi Heavy Industries, Inc. (MHI) filed suit in the U.S. District Court for the District of Maryland against PG&E NEG, PG&E National Energy Group, LLC (NEG LLC) and PG&E National Energy Group Construction Company, LLC (NEG Construction), involving a turbine purchase agreement and related contracts. On or about July 21, 2003, PG&E NEG notified the District Court of the automatic stay of litigation imposed by the bankruptcy laws. In its complaint, MHI alleges damages totaling approximately $300 million under the turbine purchase agreement and related contracts. MHI's claims arise from a dispute between the parties to a turbine purchase agreement regarding payments allegedly past due from NEG Construction in respect of reservation fees ($9.5 million) and gas generator equipment manufacture ($30 million). MPS also requested that PG&E NEG cash collateralize its $75 million guarantee issued in connection with the turbine purchase agreement. PG&E NEG and NEG Con struction have maintained (and will maintain in defense of MHI's claims) that no amounts were or are due.

As a result of PG&E NEG's Chapter 11 filing, on August 5, 2003, the District Court entered an order staying the litigation. MHI has voluntarily dismissed, without prejudice, its claims against NEG LLC, and has opposed the District Court's stay order. NEG Construction intends to oppose MHI's response to the District Court's stay order.

The outcome of this matter is not expected to have a material adverse effect on PG&E Corporation's results of operations or financial condition. Effective July 8, 2003, PG&E NEG's results will no longer be consolidated into PG&E Corporation's financial results (see Note 1).

PG&E Corporation has identified three reportable operating segments based on similarities in the following characteristics:

Segment information for the three and six months ended June 30, 2003, and 2002, was as follows:

The indenture, dated as of July 2, 2003, does not contain restrictions on the ability of the Utility and PG&E NEG to incur debt.

ITEM 2: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

PG&E Corporation is a holding company headquartered in San Francisco, California: its principal subsidiary, the Pacific Gas and Electric Company (Utility), is an operating public utility engaged primarily in the business of providing electricity, natural gas distribution, and transmission services throughout most of Northern and Central California.

On April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the federal Bankruptcy Code (Bankruptcy Code) in the U.S. Bankruptcy Court for the Northern District of California (referred to as the "Bankruptcy Court" in this report's discussion of the Utility's Chapter 11 filing). Pursuant to Chapter 11 of the 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 of Financial Condition and Results of Operations (MD&A) and in Note 2 of the Notes to the Consolidated Financial Statements.

~~While~~for the District of Maryland, Greenbelt Division (referred to as the "Bankruptcy Court" in ~~bankruptcy, the Utility is not allowed~~this report's discussion of PG&E NEG's Chapter 11 filing). Pursuant to ~~pay liabilities incurred before it filed for bankruptcy without permission from~~Chapter 11 of the Bankruptcy ~~Court. Additionally,~~

Since filing for bankruptcy, the Utility has received permission from the Bankruptcy Court to make payments on (1) pre- and post-petition interest on certain claims, (2) pre-petition amounts payable to qualifying facilities (QFs) and certain other vendors, and (3) matured pre-petition secured debt.

Since filing for bankruptcy, the Utility has been accruing interest on its pre-petition liabilities at the required rates included in the Utility's proposed plan of reorganization. As a result, the payment of such interest did not have a material adverse impact on its financial condition or results of operations.

The Utility will continue to accrue interest on its pre-petition liabilities at the required rates in 2003. However, due to the uncertainty of the ultimate outcome of the bankruptcy proceedings, the Utility is not able to estimate the amount of interest that will be paid in 2003 and beyond.

The Utility and PG&E Corporation have jointly filed a proposed plan of reorganization (Plan) that, if approved, would enable the Utility to emerge from bankruptcy. In November 2002, the Bankruptcy Court began the confirmation trial to determine which plan, if any, the Bankruptcy Court will confirm. On March 4, 2003, the Bankruptcy Court ordered the Utility, the CPUC, and other parties involved in the confirmation trial to participate in settlement negotiations. On March 11, 2003, the Bankruptcy Court then issued an order staying nearly all the proceedings in the confirmation trial until May 12, 2003. On April 23, 2003, the Bankruptcy Court extended this stay for an additional 30 days. A status conference is scheduled for June 16, 2003. PG&E Corporation and the Utility are not able to predict the ultimate outcome of the Utility's bankruptcy proceedings, including which plan, if any, the Bankruptcy Court may confirm.

Both the Plan and the alternative plan propose issuing new debt as part of the reorganization. PG&E Corporation and the Utility have incurred, and will continue to incur throughout the reorganization process, legal, accounting, trustee, and other fees associated with the proposed debt issuance. In addition, PG&E Corporation and the Utility have incurred and will continue to incur consulting fees for assistance with the implementation of either plan. Though a small amount of the costs directly related to the proposed debt issuance have been capitalized, the majority of the reorganization costs have been expensed and are included in Reorganization Professional Fees and Expenses in PG&E Corporation's and the Utility's Consolidated Statements of Operations.

Although the Utility still relies on electricity supplied by DWR contracts to service a significant portion of its total load, on January 1, 2003, the Utility and other California IOUs resumed procuring electricity to meet their customers' residual net open position under California Senate Bill (SB) 1976. In order to enter into short-term purchase contracts needed to cover its residual net open position, the Utility has posted collateral with the ISO and several other counterparties.

For further discussion of the California energy crisis, the Utility's voluntary petition for relief under the Bankruptcy Code, the status of the Chapter 11 confirmation hearings and the provisions of SB 1976, see Note 2 of the Notes to the Consolidated Financial Statements.

factors causing PG&E NEG currently is focused on power generation and natural gas transmission in the United States. As a result of the sustained downturn in the power industry, PG&E NEG and its affiliates have experienced a financial downturn, which caused the major credit rating agencies to downgrade PG&E NEG's and its affiliates' credit ratings to below investment grade. PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling $2.7 billion, buttake this ~~debt is non-recourse to PG&E NEG.~~

PG&E NEG, its subsidiaries, and their lenders have been engaged in discussions to restructure PG&E NEG's and its subsidiaries' debt obligations and other commitments since October 2002. No agreement has been reached yet and there can be no assurance that an agreement will be reached. Any restructuring agreement that may be reached would be implemented through a reorganization proceeding under Chapter 11 of the Bankruptcy Code. Although PG&E NEG and its subsidiaries are continuing their efforts to maximize cash and reduce liabilities, such efforts are not expected to restore the financial condition of PG&E NEG and its subsidiaries. Absent a negotiated agreement, the lenders may exercise their default remedies or force PG&E NEG and certain of its subsidiaries into an involuntary proceeding under the Bankruptcy Code. Notwithstanding the status of current negotiations, PG&E NEG and certain of its subsidiaries also may elect to voluntarily seek protection under the Bankruptcy Codeby the end of the second quarter of 2003. Although PG&E Corporation continues to provide assistance to PG&E NEG, its subsidiaries and its lenders in their negotiations, management does not expect the outcome of any bankruptcy proceeding involving PG&E NEG or any of its subsidiaries to have a material adverse effect on the financial condition of PG&E Corporation or the Utility. The factors affecting PG&E NEG's business causing these defaults and the principal actions being taken by PG&E NEGaction are discussed ~~later~~ in this MD&A and in Note 3 of the Notes to the Consolidated Financial Statements.

The Consolidated Financial Statements of PG&E Corporation and of the Utility have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets, and repayment of liabilities in the ordinary course of business. However, as a result of the Chapter 11 filings of both the Utility and PG&E NEG and certain of its subsidiaries, as further discussed below, such realization of assets and liquidation of liabilities are ~~restructuring their operations~~subject to increase cash, reduce financial obligations, dispose of merchant plant facilities, and decrease energy trading operations. PG&E NEG's objective is to limit its asset trading and risk management activities to only what is necessary for energy management services to facilitate the transition of PG&E NEG's merchant generation facilities through their sale, transfer or abandonment. PG&E NEG will then further reduce and transition to retain only limited capabilities to ensure fuel procurement and power logistics for PG&E NEG's retained independent power plant operations.

PG&E Corporation has ~~substantial financial commitments~~identified three reportable operating segments:

These segments were determined based on similarities in ~~connection with agreements entered into supporting~~ the ~~Utility's and PG&E NEG's operating, construction, and development activities.~~following characteristics:

These three reportable operating segments provide different products and services and are subject to ~~such disclosures included~~different forms of regulation or jurisdiction. Financial information about each reportable operating segment is provided in this MD&A and in Note 67 of the Notes to the Consolidated Financial Statements.

This MD&A explains the general financial condition and the results of operations of PG&E ~~NEG~~

~~PG&E NEG's~~Corporation and its ~~subsidiaries' guarantees fall into four broad categories:~~subsidiaries, including:

This is a combined Quarterly Report on Form 10-Q of PG&E Corporation and the Utility and includes separate Consolidated Financial Statements for each of these two entities. The Consolidated Financial Statements of PG&E Corporation reflect the accounts of PG&E Corporation, the Utility, PG&E NEG, ~~is currently in default under various debt agreements~~ and ~~guaranteed equity commitments totaling approximately $2.9 billion. In addition,~~ other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.7 billion, but this debt is non-recourse to PG&E NEG. On November 14, 2002, PG&E NEG defaulted on the repaymentwholly owned and controlled subsidiaries. The Consolidated Financial Statements of the ~~$431 million 364-day tranche of its corporate revolving credit facility (Corporate Revolver). Loans and letters of credit outstanding as of March 31, 2003, under~~Utility reflect the ~~two-year tranche~~accounts of the ~~Corporate Revolver was $258 million, $185 million of letters of credit~~Utility and ~~$73 million of loans. The default under~~its wholly owned and controlled subsidiaries. This combined MD&A should be read in conjunction with the ~~Corporate Revolver also constitutes a cross-default as of March 31, 2003, under (1)~~Consolidated Financial Statements and Notes to the Consolidated Financial Statements included herein. Further, this Quarterly Report should be read in conjunction with PG&E NEG's Senior Notes ($1 billion outstanding), (2) its guarantee of a turbine revolving credit agreement ($205 million outstanding), and (3) its equity commitment guarantees for the GenHoldings I, LLC (GenHoldings) credit facility ($35 5 million outstanding), the La Paloma credit facility ($375 million outstanding)Corporation's and the Lake Road credit facility ($230 million outstanding). In addition, on November 15, 2002, PG&E NEG failed to pay a $52 million interest payment due under the Senior Notes. PG&E NEG currently does not have sufficient cash to meet its financial obligationsUtility's Consolidated Financial Statements and ~~has ceased making payments on its debt and equity commitments.~~

GenHoldings, an indirect subsidiary of PG&E NEG, is obligated under its credit facility to make equity contributions to fund construction of the Harquahala, Covert, and Athens generating projects. This credit facility is secured by these projects in additionNotes to the ~~Millennium generating facility. GenHoldings defaulted under its credit agreement~~Consolidated Financial Statements included in ~~October~~their combined 2002 Annual Report on Form 10-K, as amended.

This combined Quarterly Report on Form 10-Q, including this MD&A, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on information currently available to management. These forward-looking statements are identified by ~~failing to make equity contributions to fund construction draws for~~words such as "estimates," "expects," "anticipates," "plans," "believes," "could," "should," "would," "may," and other similar expressions. Actual results could differ materially from those contemplated by the ~~Athens, Harquahala, and Covert generating projects.~~ forward-looking statements.

Although PG&E ~~NEG has guaranteed GenHoldings' obligations~~Corporation and the Utility are not able to ~~make equity contributions~~predict all the factors that may affect future results, some of upthe factors that could cause future results to ~~$355 million,~~differ materially from those expressed or implied by the forward-looking statements, or from historical results, include:

Outcome of the Utility's Chapter 11 Case. PG&E ~~NEG notified~~Corporation's and the ~~GenHoldings' lenders~~Utility's future results of operations and financial conditions may be affected by the pace and outcome of the Utility's Chapter 11 case, which depends upon:

Operating Environment.The amount of operating income and ~~December 2002,~~cash flows the ~~lenders executed waivers~~Utility may record may be influenced by the following:

Legislative and Regulatory Environment.PG&E Corporation's and the Utility's business may be impacted by:

Pending Litigation and Regulatory Proceedings.PG&E Corporation's and the ~~projects~~Utility's future results of operations and financial conditions may be affected by the outcome of pending litigation and regulatory proceedings, including the 2003 General Rate Case (GRC) and proceedings to determine the allocable amount of DWR revenue requirements and the method of remittance of pass-through revenues collected by the Utility to the ~~GenHoldings lenders~~DWR.

Competition.PG&E Corporation's and the Utility's future results of operations and financial conditions may be completed. An event of default will occur if such transfer is not accomplished by such deadline. Such a default would trigger lender remedies, including the right to foreclose on Millennium, Harquahala, Athens, and Covert.affected by:

Under the waiver, PG&E NEG has re-affirmed its guarantee of GenHoldings' remaining obligation to make equity contributions to these projects of approximately $355 million. Neither PG&E NEG nor GenHoldings currently expects to have sufficient funds to make this payment. The requirement to pay $355 million will remain an obligation of PG&E NEG that would survive the transfer of the projects.

In September 1999 and March 2000, Lake Road Generating Company, LP (Lake Road) and La Paloma Generating Company, LLC (La Paloma) entered into Participation Agreements to finance the construction of the two plants. In November 2002, Lake Road and La Paloma defaulted on their obligations to pay interest and swap payments. In addition,

Accounting and Risk Management.PG&E Corporation's and the ~~failure~~Utility's future results of operations and financial conditions may be affected by new accounting pronouncements, including significant changes in accounting policies material to ~~transfer right, title and interest in, to and under~~PG&E Corporation or the Lake Road and La Paloma projects to the respective lenders by June 9, 2003 will constitute a default under the agreements. The failure to transfer the facilities would entitle t he lenders to accelerate the new indebtedness and exercise other remedies. The requirement to pay $230 million and $375 million for Lake Road and La Paloma, respectively, will remain an obligation of PG&E NEG that would survive the transfer of the projects.

PG&E NEG ~~and certain subsidiaries have provided guarantees as of January 31, 2003, to approximately 188 counterparties in support of~~Chapter 11 Proceedings. PG&E ~~ET's energy trading~~Corporation's future results of operations and ~~non-trading activities related~~financial condition may be affected by whether PG&E Corporation is determined to PG&E NEG's merchant energy portfolio in the face amount of $2.2 billion. Typically, the overall exposure under these guarantees is only a fraction of the face value of these guarantees, since not all counterparty credit limits are fully used atbe liable for any time. As of March 31, 2003, PG&E NEG and its subsidiaries' aggregate exposure under these guarantees was approximately $150 million. The amount of such exposure varies daily depending on changes in market prices and net changes in position. In light of the downgrades, some counterparties have sought and others may seek replacement security to collateralize the exposure guaranteedclaims asserted by PG&E NEG and its subsidiaries. PG&E GTN and PG&E ET have terminated the arrangements pursuant to which PG&E GTN provided guarantees on behalf of PG& E ET such that PG&E GTN will provide no new guarantees on behalf of PG&E ET.

~~At March 31, 2003, PG&E ET's estimated exposure not covered by a guarantee (excluding exposure under tolling agreements) is approximately $96 million.~~

To date, PG&E ET has met those replacement security requirements properly demanded by counterparties and has not defaulted under any of its master trading agreements although one counterparty has alleged a default. No demands have been made upon the guarantors of PG&E ET's obligations under these trading agreements. In the past, PG&E ET has been able to negotiate acceptable arrangements and reduce its overall exposure to counterparties when PG&E ET or its ~~counterparties have faced similar situations. There can be no assurance that PG&E ET can continue to negotiate acceptable arrangements~~creditors in ~~the current circumstances. PG&E NEG cannot quantify with any certainty the actual future calls on PG&E ET's liquidity.~~ PG&E NEG's and its subsidiaries' ability to meet these calls on their liquidity will vary with market price volatility, uncertainty with respect to PG&E NEG's financial condition, and the degree of liquidity in the energy markets. The actual calls for collateral will depend largely upon the ability to enter into forbearance agreements and pre- and early-pay arrangements with counterparties, the continued performance of PG&E NEG companies under the underlying agreements, whether counterparties have the right to demand such collateral, the execution of master netting agreements and offsetting transactions, changes in the amount of exposure, and the counterparties' other commercial considerations.

PG&E ET has entered into tolling agreements with several counterparties under which at its discretion, it supplies the fuel to the power plants and then sells the plant's output in the competitive market. Payments to the counterparties are reduced if the plants do not achieve agreed-upon levels of performance. The face amount of PG&E NEG's and its subsidiaries' guarantees relating to PG&E ET's tolling agreements is approximately $600 million. The tolling agreements are with: (1) Liberty Electric Power, L.P. (Liberty) guaranteed primarily by PG&E NEG and secondarily by PG&E GTN for an aggregate amount of up to $150 million; (2) DTE-Georgetown, LLC (DTE) guaranteed by PG&E GTN for up to $24 million; (3) Calpine Energy Services, L.P. (Calpine) for which no guarantee is in place; (4) Southaven Power, LLC (Southaven) guaranteed by PG&E NEG for up to $175 million; and (5) Caledonia Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million.

Liberty has provided notice to PG&E ET that the ratings downgrade of PG&E NEG constituted a material adverse change under the tolling agreement requiring PG&E ET to replace the guarantee and post security in the amount of $150 million. PG&E ET has not posted such security. Under the terms of the guarantees, Liberty has the right to terminate the agreement and seek recovery of a termination payment for a maximum amount of up to $150 million. Liberty first must proceed against PG&E NEG's guarantee, and can demand payment under PG&E GTN's guarantee only if PG&E NEG is in bankruptcy or Liberty has made a payment demand on PG&E NEG which remains unpaid five business days after the payment demand is made. In addition, PG&E ET has provided notices to Liberty of several breaches of the tolling agreement by Liberty and has advised Liberty that, unless cured, these breaches would constitute a default under the agreement. If these defaults remain uncured, PG&E ET has th e right to terminate the agreement and seek recovery of a termination payment.

By letter dated October 14, 2002, DTE provided notice to PG&E ET that the downgrade of PG&E GTN constituted a material adverse change under the tolling agreement between PG&E ET and DTE and that PG&E ET was required to post replacement security within ten days. By letter dated October 23, 2002, PG&E ET advised DTE that because there had not been a material adverse change with respect to PG&E GTN within the meaning of the tolling agreement, PG&E ET was not required to post replacement security. If PG&E ET was required to post replacement security and it failed to do so, DTE would have the right to terminate the tolling agreement and seek recovery of a termination payment.

The tolling agreement states that on or before October 15, 2002, Calpine was to have issued a full notice to proceed under its construction contract to its engineering, procurement, and construction contractor for the Otay Mesa facility. On October 16, 2002, PG&E ET asked Calpine to confirm that it had issued this full notice to proceed and Calpine was not able to do so to the satisfaction of PG&E ET. Consequently, PG&E ET advised Calpine by letter dated October 30, 2002, that it was terminating the tolling agreement effective November 29, 2002. Calpine has indicated that this termination was improper and constituted a default under the agreement, but has not taken any further action.

PG&E ET signed a tolling agreement with Southaven dated as of June 1, 2000, under which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing an investment-grade guarantee from PG&E NEG as defined in the tolling agreement. The amount of the guarantee now does not exceed $175 million. By letter dated August 31, 2002, Southaven advised PG&E ET that it believed an event of default under the tolling agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade as defined in the tolling agreement and because PG&E ET had failed to provide, within 30 days from the downgrade, substitute credit support that met the requirements of the tolling agreement. Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Southaven with a notice of default respecting Southaven's performance under the agreement and concerning the inability of the facility to inject its output into the local grid. Southaven has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.

In addition, PG&E ET signed a tolling agreement with Caledonia dated as of September 20, 2000, under which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade as defined in the tolling agreement. The amount of the guarantee does not exceed $250 million. By letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an event of default under the tolling agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade as defined in the tolling agreement and because PG&E ET had failed to provide, within 30 days from the downgrade, substitute credit support that met the requirement of the tolling agreement. Caledonia has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET provided Caledonia with a notice of default respecting Caledonia's performance under the agreement and concerning the inability of the facility to inject its output into the local grid. Caledonia has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.

On February 7, 2003, Southaven and Caledonia filed an emergency petition to compel arbitration or, in the alternative, for a temporary restraining order and preliminary injunction with the Circuit Court for Montgomery County, Maryland (Court). On March 3, 2003, the Court issued an order ruling that PG&E ET must continue to perform under the agreements. PG&E ET appealed this decision to an intermediate Maryland appellate court. However, on April 8, the highest appellate court in Maryland issued on its own motion and order taking jurisdiction of the appeal.

PG&E ET is not able to predict whether the counterparties will seek to terminate the agreements or whether the Court will grant the requested relief. Accordingly, it is not able to predict whether or the extent to which theseChapter 11 proceedings ~~will have a material adverse effect on PG&E NEG's financial condition or results of operations.~~

~~Under each tolling agreement, determination of the termination payment is based on a formula that takes into account a number of factors, including market conditions such as the price of power~~ and ~~the price of fuel. In the event of a dispute over~~ the amount of any ~~termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides~~claims for ~~mandatory arbitration. The dispute resolution process could take as long as six months to more than a year to complete. To the extent that~~which PG&E ~~ET did not pay these damages, the counterparties could seek payment under the guarantees for an aggregate amount not to exceed $600 million. PG&E NEG~~Corporation is ~~unable to predict whether counterparties will seek to terminate their tolling agreements. PG&E NEG currently does not expect~~determined to be ~~able~~liable.

As the ultimate impact of these and other factors is uncertain, these and other factors may cause future earnings to ~~pay any termination payments that may become due.~~differ materially from historical results or outcomes currently sought or expected.

PG&E NEG has issued guarantees to construction financing lenders for the performance of the contractors building the Harquahala and Covert generating projects for up to $555 million. ~~The construction contractor and various equipment vendors currently are performing under their underlying contracts.~~

Additionally, PG&E NEG has issued $100 million of guarantees to the ~~constructor~~construction contractor of the Harquahala and Covert projects to cover certain separate cost-sharing arrangements.

As a result of the settlement of the Shaw Litigation, these guarantees have been terminated.

In addition, PG&E Corporation has guaranteed the Utility's reimbursement obligation associated with certain surety bonds and the Utility's obligations to pay workers' compensation claims.

The Utility had an undiscounted environmental remediation liability of $302 million at June 30, 2003, and $331 million at December 31, 2002. During the first half of the year, the liability was reduced by $29 million primarily due to a reassessment of the estimated cost of remediation. The $302 million accrued at June 30, 2003, includes (1) $105 million related to the pre-closing remediation liability associated with divested generation facilities, and (2) $197 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, compressor stations, and manufactured gas plant sites that are either owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former gas plant sites. Of the $302 million environmental remediation liability, the Utility has recovered $155 million through rates charged to its customers, and expects to recover approximatel y $93 million of the balance in future rates. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refunds to ratepayers. The Utility also is recovering its costs from insurance carriers and from other third parties whenever it is possible.