ML033640444

Independent Spent Fuel Storage Installation License Application, Table of Contents Through Attachment a - PG&E Corp Year in Review & Financial Statistical Report

ML033640444
Person / Time
Site:	Humboldt Bay
Issue date:	12/15/2003
From:	Pacific Gas & Electric Co
To:	Document Control Desk, NRC/FSME
References
+sisprbs20051109, -RFPFR
Download: ML033640444 (205)

Text

HUMBOLDT BAY ISFSI LICENSE APPLICATION LIST OF CURRENT PAGES Paae No.

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CONTENTS 18 59 19 60 20 61 21 62 ILicense Application 22 63 23 64 24 65 2 25 66 3 26 67 4 27 68 5 28 69 6 29 70 7 30 71 8 31 72 9 32 73 33 74 Attachment A 34 75 PG&E Year In 35 76 Review & Financial 36 77 Statistical Report 37 78 38 79 PG&E Corporation 39 80 2002 Annual Report 40 81 41 82 1 42 83 2 43 84 3 44 85 4 45 86 5 46 87 6 47 88 7 48 89 8 49 90 9 50 91 10 51 92 11 52 93 12 53 94 13 54 95 14 55 96 15 56 97 16 57 98 17 58 99 1

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100 141 182 101 142 183 102 143 184 103 144 185 104 145 186 105 146 187 106 147 188 107 148 189 108 149 109 150 Attachment B 110 151 Emergency Plan 111 152 112 153 Cover Page 113 154 114 155 Table of Contents 115 156 116 157 Ii 117 158 Iii 118 159 lv 119 160 1.1-1 120 161 1.1-2 121 162 1.2-1 122 163 2.1-1 123 164 2.2-1 124 165 2.2-2 125 166 2.2-3 126 167 2.2-4 127 168 2.2-5 128 169 2.3-1 129 170 2.3-2 130 171 2.3-3 131 172 3.1-1 132 173 3.2-1 133 174 3.3-1 134 175 3.4-1 135 176 3.5-1 136 177 3.5-2 137 178 3.5-3 138 179 3.6-1 139 180 3.7-1 140 181 4.1-1 2

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4.2-1 7.2-3 3.1-4 4.2-2 7.3-1 3.1-5 4.2-3 7.3-2 4.0-1 4.2-4 7.4-1 4.0-2 4.2-5 8.1-1 5.0-1 4.2-6 8.1-2 5.0-2 4.2-7 8.2-1 4.2-8 TS Bases 4.2-9 PML-03-041, Sheet 1 Table of Contents 4.2-10 PML-03-041, Sheet 2 B3.0-1 4.2-11 PML-03-041, Sheet 3 B3.0-2 4.2-12 B3.0-3 4.2-13 Attachment C B3.0-4 4.2-14 Provosed Technical B3.0-5 4.3-1 Specifications B3.0-6 4.3-2 B3.1 -1 4.4-1 Technical B3.1-2 4.4-2 Specifications B3.1-3 5.1-1 Table of Contents B3.1-4 5.1-2 1.1-1 B3.1-5 5.1-3 1.1-2 B3.1-6 5.1-4 1.1-3 B3.1-7 5.2-1 1.2-1 B3.1-8 5.2-2 1.2-2 B3.1-9 5.2-3 1.3-1 B3.1 -10 5.2-4 1.3-2 B3.1-1 1 5.2-5 1.3-3 5.2-6 1.3-4 Attachment D 5.3-1 1.4-1 Training Program 5.3-2 1.4-2 5.3-3 1.4-3 1 6.1-1 2.0-1 6.2-1 2.0-2 Attachment E 6.2-2 2.0-3 Quality Assurance Program 6.2-3 2.0-4 6.3-1 2.0-5 Cover Page 6.4-1 3.0-1 Change Synopses 6.5-1 3.0-2 I 7.1-1 3.1-1 2 7.2-1 3.1-2 Contents 7.2-2 3.1-3 i 3

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ii 17.16-1 iii 17.17-1 iv 17.17-2 17.1-1 17.17-3 17.1-2 17.17-4 17.1-3 17.17-5 17.14 17.18-1 17.1-5 17.18-2 17.1-6 17.18-3 17.1-7 17.184 17.1-8 Table 17.1-1, Sheet 1 17.1-9 Table 17.1-1, Sheet 2 17.2-1 Table 17.1-1, Sheet 3 17.2-2 Table 17.1-1, Sheet 4 17.2-3 Table 17.1-1, Sheet 5 17.2-4 Table 17.1-1, Sheet 6 17.2-5 Table 17.1-1, Sheet 7 17.2-6 Table 17.1-1, Sheet 8 17.2-7 Table 17.1-1, Sheet 9 17.2-8 Figure 17.1-1 17.2-9 Figure 17.1-2 17.2-10 17.3-1 Attachment F 17.3-2 Proposed 17.3-3 Decommissioning Plan 17.4-1 17.5-1 i 17.5-2 1-1 17.5-3 2-1 17.6-1 2-2 17.7-1 2-3 17.7-2 3-1 17.8-1 4-1 17.9-1 5-1 17.10-1 6-1 17.10-2 6-2 17.11-1 7-1 17.12-1 17.13-1 17.14-1 17.15-1 4

HUMBOLDT BAY ISFSI LICENSE APPLICATION CONTENTS License Application Attachment A - PG&E YEAR IN REVIEW & FINANCIAL STATISTICAL REPORT PG&E Corporation - 2002 Annual Report Attachment B - EMERGENCY PLAN Attachment C - PROPOSED TECHNICAL SPECIFICATIONS Proposed Technical Specifications for Humboldt Bay Independent Spent Fuel Storage Installation (ISFSI)

Technical Specification Bases for Humboldt Bay Independent Spent Fuel Storage Installation (ISFSI)

Attachment D - TRAINING PROGRAM Attachment E - QUALITY ASSURANCE PROGRAM Quality Assurance Program Table Quality Assurance Program Figures Attachment F - PRELIMINARY DECOMMISSIONING PLAN I

Humboldt Bay Independent Spent Fuel Storage Installation License Application Pacific Gas and Electric Company Eureka, California

Table of Contents 1.0 General and Financial Information 2.0 Technical Qualifications 3.0 Technical Information - Safety Analysis Report 4.0 Conformity with General Design Criteria 5.0 Operating Procedures - Administrative and Management Controls 6.0 Quality Assurance Program 7.0 Training Program 8.0 Inventory and Records Requirements 9.0 Physical Protection 10.0 Decommissioning Plan 11.0 Emergency Plan 12.0 Environmental Report 13.0 Proposed License Conditions Attachments A PG&E Corporation 2002 Annual Report B Emergency Plan C Proposed Technical Specifications D Training Program E Quality Assurance Program F Preliminary Decommissioning Plan 1.0 General and Financial Information 1.1 Application for License In accordance with the requirements of 10 CFR 72, Pacific Gas and Electric Company (PG&E) hereby submits a site-specific license application to construct and operate an Independent Spent Fuel Storage Installation (ISFSI) located at the site of the Humboldt Bay Power Plant (HBPP) in Eureka, Califomia. The proposed facility is named the Humboldt Bay ISFSI.

This application for the proposed ISFSI contains information required by the provisions of 10 CFR 72, Subpart B and was prepared using the guidance of Regulatory Guide 3.50, Revision 1. The application consists of the following:

a. The license application.

b. The technical information and safety analysis report required by 10 CFR 72.24. This is provided as a separate document titled "Humboldt Bay Independent Spent Fuel Storage Installation Safety Analysis Report".

c. The Emergency Plan required by 10 CFR 72.32. This is provided as a separate document titled "Humboldt Bay Independent Spent Fuel Storage Installation Emergency Plan." (Attachment B)

d. The proposed technical specifications. These are provided as a separate document titled "Humboldt Bay Independent Spent Fuel Storage Installation Proposed Technical Specifications."

(Attachment C)

e. The environmental report required by 10 CFR 72.34. This is provided in a separate document titled "Humboldt Bay Independent Spent Fuel Storage Installation Environmental Report."

f. Security information as required by 10 CFR 72, Subpart H. The physical security program for the Humboldt Bay ISFSI is being submitted under separate cover as documents titled "Humboldt Bay Independent Spent Fuel Storage Installation Physical Security Plan",

"Humboldt Bay Independent Spent Fuel Storage Installation Safeguards Contingency Plan", and "Humboldt Bay Independent Spent Fuel Storage Installation Security Training" and Qualificabon Plan." (Reference PG&E Letter HIL-03-002, dated December 9, 2003.)

g. A training program as required by 10 CFR 72.192. This is provided as a separate document titled "Humboldt Bay Independent Spent Fuel Storage Installation Training Program." (Attachment D)

h. A description of the quality assurance program required by 10 CFR 72.24(n). This is provided as a revision to Diablo Canyon Power Plant (DCPP) Quality Assurance Program contained in the DCPP Final Safety Analysis Report Update. (Attachment E) 1.2 Applicant Pacific Gas and Electric Company is a wholly owned subsidiary of PG&E Corporation and will be the owner of the Humboldt Bay Independent Spent Fuel Storage Installation.

The address for PG&E at Humboldt Bay Power Plant is:

Pacific Gas and Electric Company Humboldt Bay Power Plant 1000 King Salmon Avenue Eureka, CA 95503 1.3 Description of Business of Applicant Pacific Gas and Electric Company, including its subsidiaries, is a wholly owned subsidiary of PG&E Corporation, which was incorporated in 1995.

PG&E Corporation is a holding company based in San Francisco, California, which provides energy services throughout North America.

Pacific Gas and Electric Company is an operating public utility primarily regulated by the Califomia Public Utilities Commission and engaged principally in the business of providing electric and natural gas services throughout most of northern and central California. The principal executive offices of PG&E Corporation are located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105. The principal executive offices of Pacific Gas and Electric Company are located at 77 Beale Street, P.O. Box 770000, San Francisco, California, 94177.

As of December 31, 2002, PG&E Corporation had $33.7 billion in assets.

PG&E Corporation generated $12.5 billion in operating revenues for 2002.

As of December 31, 2002, PG&E Corporation and its subsidiaries and affiliates had approximately 22,000 employees. As of December 31, 2002, PG&E had $24.5 billion in assetsand generated $10.5 billion in operating revenues for 2002.

As of December 31, 2002, PG&E had approximately 20,400 employees and it is the sole owner and operator of HBPP.

1.4 Legal Status and Organization PG&E is a corporation organized and exists under the laws of the State of California.1 Its principal office is located in San Francisco, California at the address stated above. PG&E is not foreign owned, controlled or dominated and makes this application on its own behalf. PG&E is not acting as an agent or representative of any other person. A list of officers is provided in the PG&E Corporation 2002 Annual Report. This report is included as Attachment A.

1.5 Financial Qualifications PG&E will have the financial qualifications to construct and operate the Humboldt Bay ISFSI. The total cost of building and operating the ISFSI through 2015 is estimated to be approximately $66 million. The cost assumes six storage casks are loaded to completely empty the spent fuel pool at HBPP of spent fuel and GTCC waste. Additional operating costs, beyond 2015 are estimated to be $2.7 million per year. All costs are in year 2002 dollars. The funds necessary to cover the costs of construction and operating the ISFSI will be paid from the Humboldt Decommissioning Trusts as approved by the Califomia Public Utilities Commission.

Presently, PG&E is an electric utility subject to rates established by the California Public Utilities Commission (CPUC). As long as PG&E remains the licensee, both capital expenditures and operation and maintenance costs will be covered by revenues derived from electric rates. PG&E's assets and revenues are discussed above. On April 6, 2001, PG&E filed a petition for relief under Chapter 11 of the United States Bankruptcy Code.

On September 20, 2001, PG&E filed with the Bankruptcy Court a comprehensive plan of reorganization for PG&E. The plan of reorganization involves a complete restructuring of PG&E's businesses and operations. Under a settlement agreement executed with the CPUC Staff in June 2003, PG&E Corporation, PG&E and the CPUC Staff agreed to jointly support a new plan of reorganization (Settlement Plan) submitted to the Bankruptcy Court under which PG&E would be a vertically integrated utility. To become effective, among other conditions, the settlement agreement must be entered into by the CPUC by December 31, 2003. Assuming that all approvals are received in a timely fashion, PG&E anticipates exiting Chapter 11 bankruptcy in the first quarter of 2004. The funds necessary for decommissioning of the proposed ISFSI are estimated to be approximately $900,000 when escalated to 2002 dollars. The detailed cost estimate was reflected in PG&E's March 2003 Decommissioning Funding Report to the Nuclear Regulatory Commission (NRC) as required by 10 CFR 50.75 (f)(1). PG&E has established an external sinking fund account for decommissioning HBPP Unit 3, as discussed in the March 2003 Decommissioning Funding Report to the NRC. This account contains monies for decommissioning the ISFSI.

1.6 Site Location and Completion Dates The Humboldt Bay ISFSI will be located at the HBPP within the existing owner-controlled area in Humboldt County, California.

PG&E requests that the 10 CFR Part 72 license and associated 10 CFR Part 50 license amendment be issued by the end of 2005.

Assuming no delays in the review process and NRC issuance of the Humboldt Bay ISFSI license in 2005, PG&E will apply to the CPUC to use Humboldt Bay Decommissioning Trust funds for procurement and construction of the ISFSI and after CPUC approval, will proceed with ISFSI procurement and construction.

1.7 Communications It is requested that communications pertaining to this application be sent to:

Gregory M. Rueger Senior Vice President Generation and Chief Nuclear Officer 77 Beale Street, MC B32 San Francisco, CA 94105 Copies should also be sent to:

Terence L. Grebel Manager, Regulatory Projects Diablo Canyon Power Plant P.O. Box 56 Avila Beach, CA 93424 Richard F. Locke Pacific Gas and Electric Law Department 77 Beale Street, MC B30A San Francisco, CA 94105 2.0 Technical Qualifications The technical qualifications of the PG&E staff for managing the design, construction and operation of the Humboldt Bay ISFSI are contained in Chapter 9 of the Humboldt Bay ISFSI Safety Analysis Report (SAR). Due to the passive nature of the ISFSl and its relatively infrequent demand on operations personnel, it is expected that ISFSI operations can be scheduled so the existing HBPP organization can accommodate the ISFSI storage-related responsibilities without the need for obtaining additional personnel. Qualified contractor personnel may be used for cask handling and transport activities onsite. PG&E will maintain an adequate staff of trained and certified personnel for the conduct of all ISFSI operations.

3.0 Technical Information - Safety Analysis Report The Humboldt Bay ISFSI will use sealed multi-purpose canisters (MPCs) placed inside Holtec HI-STAR HB storage overpacks to store spent fuel and other approved contents from the HBPP Unit 3. The spent fuel assemblies that meet the Humboldt Bay ISFSI Technical Specifications and Humboldt Bay ISFSI SAR Chapter 10 requirements will be placed into the MPCs under water in the HBPP Unit 3 spent fuel pool. The loaded MPCs and associated HI-STAR HB cask will then be lifted out of the water. The lid will then be welded and the outer surface decontaminated. The water in the MPC fuel cavity will be removed; any remaining water in the cavity dried, the cavity backfilled with helium, and the vent and drain ports in the lid welded closed. The HI-STAR HB cask will then be transported to the ISFSI storage vault. At the ISFSI storage vault, the HI-STAR HB will be placed in the vault where it will remain until it is taken off-site by the Department of Energy. The HI-STAR HB storage overpack and vault are totally passive systems with sufficient cooling to maintain safe fuel cladding temperatures. The HI-STAR HB storage cask provides shielding, and no radioactive materials are anticipated to be released under any operating conditions.

The Humboldt Bay ISFSI is designed to store the spent fuel resulting from the operation of the HBPP Unit 3. The total spent fuel storage design capacity of the facility is 400 spent fuel assemblies or up to five casks including a sixth cask for storage of greater than Class C waste.

The SAR filed with this application describes the design criteria for the dry cask storage system, transporter, storage vault, and all related matters pertaining to operation of the ISFSI. The Holtec International HI-STAR 100 System Final Safety Analysis Report Revision I contains detailed descriptions of the dry cask storage system and how it meets the prescribed criteria. This documentation has been previously filed with the NRC and is specifically relied upon in this application, as referenced herein. The NRC has previously issued Certificate of Compliance 72-1008 for the HI-STAR 100 system. The combination of the Humboldt Bay ISFSI SAR and the Holtec reports listed in the Humboldt Bay SAR Section 1.5 provide all the information required by 10 CFR 72.

The Humboldt Bay ISFSI SAR follows the format specified in Regulatory Guide 3.62, "Standard Format and Content for the Safety Analysis Report for Onsite Storage of Spent Nuclear Fuel Storage Casks," dated February 1989. The SARs describing the vendor dry cask storage system follow the format specified in Regulatory Guide 3.61, "Standard Format and Content for a Topical Safety Analysis Report for a Spent Fuel Dry Storage Cask", Revision 1, February 1989.

4.0 Conformity with General Design Criteria Subpart F of 10 CFR 72 provides the general design criteria for an ISFSI. The Humboldt Bay ISFSI complies with all the applicable 10 CFR 72 general design criteria. The specific conformance of the Humboldt Bay ISFSI to the 10 CFR 72 general design criteria is addressed in detail in the SAR and other documents attached thereto. A detailed cross-reference of the design criteria to the applicable sections of the SAR and other documents is provided in SAR Table 4.2-1 1.

5.0 Operating Procedures-Administrative and Management Controls The Humboldt Bay ISFSI will be operated under the same management organization responsible for operation of the HBPP Unit 3. This organization is described in Chapter 9 of the Humboldt Bay ISFSI SAR.

Procedures for operation of the Humboldt Bay ISFSI will be developed by PG&E and incorporated into existing HBPP station procedures. Operation of the Humboldt Bay ISFSI will consist of loading spent fuel and associated nonfuel hardware fuel into MPCs and HI-STAR HB casks, sealing the MPCs, transporting the HI-STAR HB and MPC to the ISFSI storage vault, and placing the loaded HI-STAR HB cask into the ISFSI storage vault.

Administrative controls and operating procedures, which will be in effect for operation of the ISFSI, are described in Chapter 9 of the SAR. Operating controls and limits are addressed in Chapter 10 of the SAR.

6.0 Quality Assurance Program All activities associated with the Humboldt Bay ISFSI that are considered important to safety will be conducted in accordance with the NRC-approved 10 CFR 50 Appendix B DCPP Quality Assurance Program, as revised to be applicable to the Humboldt Bay ISFSI. Adherence to this program ensures that, as required by Subpart G to 10 CFR 72, an adequate quality assurance program will be implemented. A description of the Quality Assurance Program is provided in Chapter 11 of the SAR and the proposed program is included as Attachment E.

7.0 Training Program As discussed in Section 9.3 of the Humboldt Bay ISFSI SAR, and in Attachment E, personnel working at the Humboldt Bay ISFSI will receive training to provide and maintain a well-qualified work force for safe operation of the ISFSI.

8.0 Inventory and Records Requirements The inventory and records system for the stored spent fuel, associated nonfuel hardware, and overall operation of the ISFSI are described in Section 5.3 of the Humboldt Bay ISFSI SAR. This system will meet the requirements of 10 CFR 72.72.

9.0 Physical Protection The physical security program for the Humboldt Bay ISFSI is provided in the Humboldt Bay ISFSI Physical Security Plan, the Safeguards Contingency Plan, and the Security Training and Qualification Plan. These documents contain safeguards information and are protected and controlled in accordance with 10 CFR 2.790(d) and 10 CR 73.21. These documents are being submitted under separate cover. (Reference PG&E Letter HIL-03-002 dated December 9, 2003.)

10.0 Decommissioning Plan The dry cask storage system design concept used at the Humboldt Bay ISFSI features inherent ease and simplicity for decommissioning. At the end of its service lifetime, decommissioning of the Humboldt Bay ISFSI will be accomplished by removing the HI-STAR HBs containing the spent fuel from the storage vault for transportation offsite, decontaminating as required exposed surfaces by conventional means, releasing materials for either re-use or disposal, and finally releasing the site for unrestricted use.

Due to the zero-leakage design of the MPC, no residual contamination is expected to be left behind on the concrete storage vault. The storage vault, fences, and peripheral utility structures require no decontamination or special handling after the last HI-STAR HB is removed.

A preliminary decommissioning plan is provided in Attachment F.

11.0 Emergency Plan The Humboldt Bay ISFSI Emergency Plan will be used to provide the necessary guidelines concerning responsibilities, authorities, actions, and resources required to cope with the range of occurrences that may arise at the Humboldt Bay ISFSI. The Humboldt Bay ISFSI Emergency Plan has been developed to reflect the actions to be taken during postulated events described in Chapter 8 of the SAR.

The Humboldt Bay ISFSI Emergency Plan is included as Attachment B.

12.0 Environmental Report The environmental impacts of all aspects of the Humboldt Bay ISFSI have been evaluated in the Environmental Report enclosed with the License Application.

The Environmental Report has been prepared to meet the requirements of Subpart A of 10 CFR 51 and Subpart E of 10 CFR 72. The environmental impacts will not be significant. This conclusion is consistent with the NRC's generic finding in NUREG-0575, "Final Generic Environmental Impact Statement (FGEIS) on Handling and Storage of Spent Light-Water Power Reactor Fuel" issued in 1979 that storage of light water spent fuel has an insignificant impact on the environment.

13.0 Proposed License Conditions The proposed license conditions are submitted as Attachment C to this License Application.

HUMBOLDT BAY ISFSI LICENSE APPLICATION ATTACHMENT A PG&E YEAR IN REVIEW & FINANCIAL STATISTICAL REPORT

PG&E Corporation 2002 Annual Report Corporate Overview PG&E Corporation is a national energy company with approximately $12 billion in revenues in 2002, and approximately $34 billion in assets at the end of 2002. It is the parent company of Pacific Gas and Electric Company (the Utility), one of the largest combination natural gas and electric utilities in the United States, serving Northern and Central California. PG&E Corporation is also the parent company of PG&E National Energy Group, Inc. (PG&E NEG), an integrated energy company with operations that include power generation, wholesale energy marketing and trading, risk management, and natural gas transmission in North America.

Financial Highlights PG&E Corporation (unaudited, dollars In millions, except per share mounts) 2002 2001 Operating Revenues .............. .......... $ 12,495 $ 12,210 Net Income (Loss)

Net income from operations (l) ................................ $ 864 $ 1,099 Headroom 2)............................................ 1,051 Items impacting comparability e) .... (2,789) _

Reported net income (loss) ............................... $ (874) $ 1,099 Income (Loss) Per Common Share, fully diluted Net income from operations () ...... $ 2.33 $ 3.02 Headroom (2)........................................... 2.83 Items impacting comparability e) . ... .. (7.52)

Reported net income (loss) per common share ............... $ (2.36) $ 3.02 Dividends Per Common Share ............................... $ $_- _

Total Assets .............................................. $ 33,696 $ 35,963 Number of common shareholders at December 31 ................ 117,816 125,739 Number of common shares outstanding at December 31 ............ 405,486,015 ') 387,898,848 (4)

Net income from operations does not meet the guidelines of accounting principles generally accepted in the United States of America. It excludes items impacting comparability and should not be considered an alternative to net income.

(2) Headroom reflects the current recovery in the Utility's existing electric rates of prior uncollected costs previously written-off in accordance with accounting principles generally accepted in the United States of America.

(3) Items impacting comparability for the year ended December 31, 2002 include PG&E NEG impairments and write-offs of merchant assets, long-term turbine prepayments and related capitalized development and construction costs of $1.6 billion

($4.21 per share) related to the planned sale, transfer or abandonment of these assets; an impairment charge of $767 million

($2.07 per share) related to the planned sale of USGen New England and Energy Trading Canada which are assets held for sale and classified as discontinued operations; net charges of $156 million ($0.42 per share) for hedge contracts, primarily interest rate swaps, at PG&E NEG that were terminated by counterparties as a result of defaults in the terms of various financing arrangements; the net effect of incremental interest costs of $351 million ($0.95 per share) from the increased amount and cost of debt resulting from the Utility's Chapter 11 filing; the write-off of $68 million ($0.18 per share) of previously capitalized debt costs and discounts associated with PG&E Corporation's prepayment of its Tranche A loan and changes in the terms of its Tranche B loan in conjunction with its loan waiver extension; the net cumulative effect of a changes in accounting principle and mark-to-market methodology of $55 million ($0.14 per share); restructuring costs at PG&E NEG of $27 million ($0.07 per share), generally consisting of external legal consulting and financial advisory fees, severance costs and lease cancellation costs; increased costs of $132 million ($0.36 per share) related to the Utility's Chapter 11 filing and generally consisting of external legal consulting and financial advisory fees; and net tax charges of $66 million

($0.18 per share) primarily related to a valuation allowance against state deferred tax assets of PG&E NEG that are not probable of future realization. Partially offsetting these charges was the Utility's net reversal of wholesale energy charges of

$352 million ($0.95 per share); and the third quarter change in the mark-to-market value of PG&E NEG warrants of

$42 million ($0.11 per share) outstanding under PG&E Corporation's loans.

1

Items impacting comparability in 2001 include the collection of previously written-off transition costs of $458 million

($1.26 per share) and the cumulative effect of a change in accounting principle of $9 million ($0.02 per share) partially offset by a loss of $66 million ($0.18 per share) on a involuntary terminations of gas transportation hedges resulting from the Utility's bankniptcy; incremental interest costs of $262 million ($0.72 per share) from the increased amount and cost of debt resulting from the California energy crisis and the UtWity's bankruptcy; increased costs of $78 million ($0.21 per share) related to the Utility's bankruptcy and generally consisting of external legal consulting and financial advisory fees; the net prior year impacts associated with current year decisions issued by the California Public Utilities Commission on rehearings of the Utility's 1999 General Rate Case of $26 million ($0.07 per share); and the loss on termination of certain contracts with Enron Corp. of $35 million ($0.10 per share) attributed to its bankruptcy filing.

(4) The common shares outstanding include 23,815,500 shares held by a wholly owned subsidiary of PG&E Corporation. These shares are treated as treasury stock in the Consolidated Financial Statements.

2

SEIECrED FINANCIAL DATA (in millions, except per share amounts) 2002 2001 2000 1999 1998 PG&E Corporation (1)

For the Year Operating revenues ....................... $ 12,495 $ 12,210 $ 12,568 $ 10,956 $ 11,532 Operating income (loss) .................... 1,132 2,591 (4,929) 829 2,097 Income (Loss) from continuing operations ....... (57) 983 (3,423) (49) 762 Earnings (Loss) per common share from continuing operations, basic ....................... (0.15) 2.71 (9.45) (0.13) 1.99 Earnings (Loss) per common share from continuing operations, diluted ...................... (0.15) 2.70 (9.45) (0.13) 1.99 Dividends declared per common share .......... - - 1.20 1.20 1.20 At Year-End Book value per common share ............... $ 9.47 $ 11.91 $ 8.76 $ 19.13 $ 21.08 Common stock price per share ............... 13.90 19.24 20.00 20.50 31.50 Total assets ........................... 33,696 35,963 36,152 29,588 33,234 Long-term debt (excluding current portion)...... 4,345 7,222 5,475 6,785 7,422 PG&E NEG debt in default .................. 4,230 Rate reduction bonds (excluding current portion) . . 1,160 1,450 1,740 2,031 2,321 Financial debt subject to compromise ........... 5,605 5,651 Redeemable preferred stock and securities of subsidiaries (excluding current portion)....... 335 635 635 635 635 Pacific Gas And Electric Company (1)

For the Year Operating revenues ....................... $ 10,514 $ 10,462 $ 9,637 $ 9,228 $ 8,924 Operating income (loss) .................... 3,913 2,478 (5,201) 1,993 1,876 Income (Loss) available for (allocated to) common stock ............................... 1,794 990 (3,508) 763 702 At Year-End Total assets............................. $ 24,551 $ 25,269 $ 21,988 $ 21,470 $ 22,950 Long-term debt (excluding current portion)....... 2,739 3,019 3,342 4,877 5,444 Rate reduction bonds (excluding current portion) 1,160 1,450 1,740 2,031 2,321 Financial debt subject to compromise ......... 5,605 5,651 Redeemable preferred stock and securities (excluding current portion) ................ 286 586 586 586 586

") See Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes to the Consolidated Financial Statements for discussion of matters relating to certain data.

3

MANAGEMENT'S DISCUSSION AND ANALYSIS subsidiaries, including North Baja OF FINANCIAL CONDITION AND RESULTS OF Pipeline, TIC (NBP) (collectively, PG&E OPERATIONS GTN).

OVERVIEW PG&E NEG also has other less significant subsidiaries.

PG&E Corporation is an energy-based holding company headquartered in San Francisco, PG&E National Energy Group, LLC owns California that conducts its business through two 100 percent of the stock of PG&E NEG, GTN principal subsidiaries: Pacific Gas and Electric Holdings, LLC owns 100 percent of the stock of Company (the Utility), an operating public utility PG&E GTN, and PG&E Energy Trading Holdings, engaged primarily in the business of providing LLC owns 100 percent of the stock of PG&E ET.

electricity, natural gas distribution, and The organizational documents of PG&E NEG and transmission services throughout most of these limited liability companies require Northern and Central California, and PG&E unanimous approval of their respective boards of National Energy Group, Inc. (PG&E NEG), a directors, including at least one independent company engaged in power generation, director, before they can:

wholesale energy marketing and trading, risk

• Consolidate or merge with any entity; management, and natural gas transmission.

• Transfer substantially all of their assets to The Utility filed a voluntary petition for relief any entity; or under Chapter 11 of the United States

• Institute or consent to bankruptcy, Bankruptcy Code (Bankruptcy Code) in the insolvency or similar proceedings or Bankruptcy Court for the Northern District of actions.

California (Bankruptcy Court) on April 6, 2001.

Pursuant to Chapter 11, the Utility retains control The limited liability companies may not declare of its assets and is authorized to operate its or pay dividends unless the respective boards of business as a debtor-in-possession while being directors have unanimously approved such subject to the jurisdiction of the Bankruptcy action, and the company meets specified Court. The factors causing the Utility to take this financial requirements.

action are discussed in this Management's Discussion and Analysis of Financial Condition As a result of the sustained downturn in the and Results of Operations (MD&A) and in Note 2 power industry, PG&E NEG and its affiliates have of the Notes to the Consolidated Financial experienced a financial downturn, which caused Statements.

the major credit rating agencies to downgrade PG&E NEG's and its affiliates' credit ratings to PG&E NEG and its subsidiaries are principally below investment grade. PG&E NEG is currently located in the United States and Canada and in default under various recourse debt include:

agreements and guaranteed equity commitments

• PG&E Generating Company, LLC and its totaling approximately $2.9 billion. In addition, subsidiaries (collectively, PG&E Gen LLC); other PG&E NEG subsidiaries are in default under various debt agreements totaling

• PG&E Energy Trading Holdings approximately $2.5 billion, but this debt is non-Corporation and its subsidiaries recourse to PG&E NEG. PG&E NEG and these (collectively, PG&E Energy Trading or subsidiaries continue to negotiate with their PG&E ETl; lenders regarding a restructuring of this

• PG&E Gas Transmission Corporation and indebtedness and these commitments. The its subsidiaries (collectively, PG&E GTC), factors affecting PG&E NEG's business causing which includes PG&E Gas Transmission, these defaults and the principal actions being Northwest Corporation and its taken by PG&E NEG are discussed later in this 4

MD&A and in Note 3 of the Notes to the . How information is reported to and used Consolidated Financial Statements. by PG&E Corporation's chief operating decision makers.

During the fourth quarter of 2002, PG&E NEG and certain subsidiaries have agreed to sell or These three reportable operating segments have sold certain assets, have abandoned other provide different products and services and are assets, and have significantly reduced energy subject to different forms of regulation or trading operations. As a result of these actions, jurisdictions. Financial information about each PG&E NEG has incurred pre-tax charges to reportable operating segment is provided in this earnings of approximately $3.9 billion in 2002. MD&A and in Note 17 of the Notes to the PG&E NEG and its subsidiaries are continuing Consolidated Financial Statements.

their efforts to abandon, sell, or transfer additional assets in an ongoing effort to raise This discussion and analysis explains the general cash and reduce debt, whether through financial condition and the results of operations negotiation with lenders or otherwise. As a of PG&E Corporation and its subsidiaries result, PG&E NEG expects to incur additional including:

substantial charges to earnings in 2003 as it

• Factors that affect each business; restructures its operations. In addition, if a restructuring agreement is not reached and the . A comparison of revenues and expenses lenders exercise their default remedies, or if the and why they changed between years; financial commitments are not restructured,

• Where earnings came from; PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced

• How all of this affects overall financial into a proceeding under the Bankruptcy Code. condition; Management does not expect that the liquidity

. What expenditures for capital projects constraints of PG&E NEG and its subsidiaries will affect the financial condition of PG&E were for 2000 through 2002, and are Corporation or the Utility. expected to be through 2004; and

. The expected sources of cash for future PG&E Corporation has identified three reportable capital expenditures.

operating segments:

This is a combined annual report of PG&E

• Utility; Corporation and the Utility and includes separate

• Integrated Energy and Marketing, or the Consolidated Financial Statements for each of Generation Business; and these two entities. The Consolidated Financial Statements of PG&E Corporation reflect the

• Interstate Pipeline Operations, or the Pipeline Business. accounts of PG&E Corporation, the Utility, PG&E NEG, and other wholly owned and controlled subsidiaries. The Consolidated Financial These segments were determined based on similarities in the following characteristics: Statements of the Utility reflect the accounts of the Utility and its wholly owned and controlled

• Economic; subsidiaries. This combined MD&A should be read in conjunction with the Consolidated

. Products and services; Financial Statements.

. Types of customers;

• Methods of distribution; Forward-lookingstatements and risk factors

• Regulatory environment; and This combined annual report, including the Letter to Shareholders and this MD&A, contains forward-looking statements that are necessarily 5

subject to various risks and uncertainties. These

• The outcome of the Utility's claims against statements are based on current expectations and the CPUC Commissioners for recovery of on assumptions which management believes are under-collected power procurement and reasonable and on information currenfly transition costs based on the federal filed available to management. These forward-looking rate doctrine.

statements are identified by words such as "estimates," "expects," "anticipates," "plans," Refundability of Amounts Previously Collected.

"believes," "could," "should," "would," "may," Whether the Utility is required to refund to and other similar expressions. Actual results ratepayers amounts previously collected depends could differ materially from those contemplated on many factors including:

by the forward-looking statements.

• Whether the CPUC determines that certain transition or procurement costs recovered Although PG&E Corporation and the Utility are in revenues collected by the Utility were not able to predict all the factors that may affect not eligible transition costs or otherwise future results, some of the factors that could reduces the amount of revenues cause future results to differ materially from authorized to recover such transition or those expressed or implied by the forward- procurement costs; looking statements, or from historical results, include:

• Whether the CPUC ultimately determines that certain past power procurement costs Recovery of Under-collectedPower Procurement incurred by the Utility were not and Transition Costs Previously Written Off reasonably incurred and should be The extent to which the Utility is able to recover disallowed; and its under-collected power procurement and

• The purposes for which the CPUC transition costs previously written off depends on ultimately determines that surcharges many factors, including:

approved by the CPUC in January, March,

• What costs the Califomia Public Utilities and May 2001 may be used.

Commission (CPUC) determines are eligible for recovery as transition costs; Outcome of the Utility's Bankruptcy Case. The pace and outcome of the Utilitys bankruptcy a When the Utility's rate freeze ended, as case will be affected by:

determined by the CPUC;

• Whether the Bankruptcy Court confirms

• Sales volatility and the level of direct the Utility's proposed plan of access customers (i.e., those customers reorganization (Utility's Plan), the who choose an alternative energy alternative plan sponsored by the CPUC provider);

and the Official Committee of Unsecured

• Changes in the Califomia Department of Creditors (the CPUC/OCC Plan), or some Water Resources' (DWR), revenue other plan of reorganization; requirements required to be remitted to

• Whether regulatory and governmental the DWR from existing retail rates; approvals required to implement a

• Changes in the Utility's authorized confirmed plan are obtained and the revenue requirements; timing of such approvals;

• Future regulatory or judicial decisions that

• Whether there are any delays in determine whether the Utility is allowed implementation of a plan due to litigation under state law to recover under-collected related to regulatory, governmental, or power procurement and transition costs Bankruptcy Court orders; and from its customers after the end of the

• Future equity or debt market conditions, rate freeze; and future interest rates, future credit ratings, 6

and other factors that may affect the investigations into "wash" or "round-trip" ability to implement either plan or affect trading, specific trading strategies and the amount and value of the securities other industry issues, with the potential proposed to be issued under either plan. for changes in industry regulations and in the treatment of PG&E NEG by state and Operating Environment. The amount of federal agencies.

operating income and cash flows the Utility may record may be influenced by the following: Regulatory Proceedings and Investigations.

PG&E Corporation's and the Utility's business

• Future regulatory actions regarding the may be affected by:

Utility's procurement of power for its retail customers; . The outcome of the Utility's various regulatory proceedings pending at the

• The terms and conditions of the Utility's CPUC and at the Federal Energy long-term generation procurement plan as Regulatory Commission (FERC); and approved by the CPUC;

. The outcome of the CPUC's pending

• The ability of the Utility to timely recover investigation into whether the California in full its costs including its procurement investor-owned utilities (IOUs), have costs; complied with past CPUC decisions, rules

• Future sales levels, which can be affected or orders authorizing their holding by general economic and financial market company formations and/or governing conditions, changes in interest rates, affiliate transactions, as well as applicable weather, conservation efforts, outages, statutes.

and the level of direct access customers; Pending Legal Proceedings. PG&E

• Tlhe demand for and pricing of natural gas Corporation's and the Utility's future results of transportation and storage services, which operation and financial conditions may be may be affected by weather, overall gas affected by the outcomes of:

fired generation, and price spreads between various natural gas delivery

• The lawsuits filed by the California points; Attorney General and the City and County of San Francisco against PG&E

• Changes in the Utility's authorized Corporation alleging unfair or fraudulent revenue requirements; and business acts or practices based on

• Acts of terrorism, storms, earthquakes, alleged violations of conditions accidents, mechanical breakdowns, or established in the CPUC's holding other events or perils that result in power company decisions; outages or damages to the Utility's assets

- The outcome of the Califomia Attorney or operations, to the extent not covered General's petition requesting revocation of by insurance.

PG&E Corporation's exemption from the Public Utility Holding Company Act of Legislative and Regulatory Entironment. PG&E 1935; and Corporation's and the Utility's business may be impacted:

• Other pending litigation.

• By legislative or regulatory changes Competition. PG&E Corporation's and the affecting the electric and natural gas Utility's future results of operations and financial industries in the United States; and condition may be affected by:

• By heightened regulatory and

. The threat of municipalization which may enforcement agency focus on the result in stranded Utility investment, loss merchant energy business including 7

of customer growth, and additional . Volatility in income resulting from barriers to cost recovery; mark-to-market accounting and changes in mark-to-market methodologies;

• Changes in the level of direct access customer cost responsibility and other

• The extent to which the assumptions surcharges related to direct access, and underlying critical accounting estimates, competition from other service providers mark-to-market accounting, and risk to the extent restrictions on direct access management programs are not realized; are removed; and

• The development of alternative energy

• The volatility of commodity fuel and technologies; electricity prices, and the effectiveness of risk management policies and procedures

• The ability to compete for gas designed to address volatility.

transmission services into Southern California and with alternative storage Efforts to Restructure PG&E NEG's Indebtedness.

providers throughout California; and Whether PG&E NEG and certain of its

• The growth of distributed generation or subsidiaries seek protection under or are forced self-generation. into a proceeding under the Bankruptcy Code will be affected by:

Environmental and Nuclear Matters. PG&E

• The outcome of PG&E NEG's negotiations Corporation's and the Utility's future results of with lenders under various credit facilities, operations and financial condition may be as well as with representatives of the affected by:

holders of PG&E NEG's Senior Notes, to

• The effect of compliance with existing restructure PG&E NEG's and its and future environmental laws, subsidiaries' indebtedness and regulations, and policies, the cost of commitments; which could be significant;

• The terms and conditions of any sale,

• Whether the Utility is able to fully recover transfer, or abandonment of certain of in rates the costs of complying with PG&E NEG's merchant assets, including its existing and future environmental laws, New England generating assets, that regulations, and policies, the cost of PG&E NEG may enter into; and which could be significant; and

• The terms and conditions under which

• Whether the Utility incurs costs in certain generating projects will be connection with its nuclear facilities that transferred to the project lenders as exceed the Utility's insurance coverage required by recent restructuring and other amounts set aside for agreements.

decommissioning and other potential liabilities. PG&E NEG OperationalRisks. PG&E Corporation's future results of operation and Accounting and Risk Management. PG&E financial condition will be affected by:

Corporation's and the Utility's future results of

• The extent to which PG&E NEG incurs operations and financial condition may be further charges to earnings as a result of affected by:

the abandonment, sale or transfer of

• The effect of new accounting assets, or termination of contractual pronouncements; commitments, whether such transactions occur in connection with restructuring of

• Changes in critical accounting estimates; PG&E NEG's indebtedness or otherwise; 8

• Any potential charges to income that embargoes, financial markets, interest rates, other would result from the reduction and industry participant failures, the markets' potential discontinuance of PG&E NEG's perception of energy merchants and other energy trading and marketing operations, factors.

including tolling transactions; Actions of PG&E NEG Counterparties. PG&E

• Any potential charges to income that Corporation's future results of operations and would result from the discontinuance or financial condition may be affected by:

transfer of any of PG&E NEG's merchant generation assets;

• The extent to which counterparties demand additional collateral in connection

• The inability of PG&E NEG, its merchant with PG&E ET's trading and nontrading asset and other subsidiaries, including US activities and the ability of PG&E NEG Gen New England, Inc., to maintain and its subsidiaries to meet the liquidity sufficient liquidity necessary to meet their calls that may be made; and commodity and other obligations.

• The extent to which counterparties seek

• The extent to which PG&E NEG's current to terminate tolling agreements and the construction of generation, pipeline, and amount of any termination damages they storage facilities are completed and the may seek to recover from PG&E NEG as pace and cost of that completion, guarantor.

including the extent to which commercial operations of these construction projects As the ultimate impact of these and other factors are delayed or prevented because of is uncertain, these and other factors may cause financial or liquidity constraints, changes future earnings to differ materially from historical in the national energy markets and by the results or outcomes currently sought or extent and timing of generating, pipeline, expected.

and storage capacity expansion and retirements by others; or by various This MD&A should be read in conjunction with development and construction risks such the Consolidated Financial Statements and Notes as PG&E NEG's failure to obtain necessary to the Consolidated Financial Statements permits or equipment, the failure of third-included herein.

party contractors to perform their contractual obligations, or the failure of Market Conditions and Business necessary equipment to perform as Environment anticipated and the potential loss of permits or other rights in connection with During 2002, adverse changes in the electric PG&E NEG's decision to delay or defer power and gas utility industry and energy construction; markets affected PG&E Corporation, the Utility,

• The impact of layoffs and loss of and PG&E NEG's business including:

personnel at PG&E NEG; and

• Contractions and instability of wholesale

• Future sales levels which can be affected electricity and energy commodity markets; by economic conditions, weather,

• Significant decline in generation margins conservation efforts, outages, and other (spark spreads) caused by excess supply factors.

and reduced demand in most regions of the United States; Current Condftions in the Energy Markets and the Economy. PG&E Corporation's future results

• Loss of confidence in energy companies of operations and financial condition will be due to increased scrutiny by regulators, affected by changes in the energy markets, elected officials, and investors as a result changes in the general economy, wars, of a string of financial reporting scandals; 9

. Heightened scrutiny by credit rating bankruptcy without permission from the agencies prompted by these market Bankruptcy Court. Additionally, changes and scandals which resulted in

. While in bankruptcy, the Utility does not lower credit ratings for many market have access to external funding from participants; and capital markets;

. Resulting significant financial distress and

• The Utility is in default under its credit liquidity problems among market participants leading to numerous financial facilities, commercial paper, floating rate notes, senior notes, pollution control loan restructurings and less market agreements, and medium-term notes, as a participation.

result of its failure to pay certain of its obligations. However, the event of default U1QUIDTY AND FINANCIAL RESOURCES under each security has been stayed in Utility accordance with the bankruptcy proceedings; and In 1998, the State of California implemented

• The Utility has been making capital electric industry restructuring and established a investments (investments in property, framework allowing generators and other plant; and equipment) out of its cash on electricity providers to charge market-based hand under the supervision of the prices for electricity sold on the wholesale Bankruptcy Court. The Utility anticipates market. The implementing legislation also that it will be able to continue making established a retail electricity rate freeze and a such necessary capital investments in the plan for recovery of generation-related costs that future, subject to Bankruptcy Court were expected to be uneconomic under the new approval.

market framework. State regulatory action further strongly encouraged the Utility to sell a majority As a result of the California energy crisis and the of its fossil fuel-fired generation facilities and Utility's bankruptcy filing, a number of qualifying made it economically unattractive to retain its facilities (QFs) requested the Bankruptcy Court remaining generation facilities. The resulting to either terminate their contracts to sell sales of generation facilities in turn made the electricity to the Utility, or have the contracts Utility more dependent on the newly deregulated suspended for the summer of 2001 so the QFs wholesale electricity market. Beginning in could sell electricity at market-based rates. Since June 2000, wholesale prices for electricity began July 2001, the Utility has entered into 264 five-to increase. Prices moderated somewhat in the year agreements with QFs (authorized by the fall before increasing to unprecedented levels in Bankruptcy Court) to assume their power November 2000 and later months. Since the purchase agreements. See Note 16 of the Notes Utility's retail rates were frozen, it financed the to the Consolidated Financial Statements for a higher costs of wholesale electricity by issuing discussion of the QF power purchase debt and drawing on its credit facilities. The agreements.

Utility's inability to recover its electric procurement costs from customers ultimately In March 2002, the Bankruptcy Court authorized resulted in billions of dollars in defaulted debt the Utility to pay certain pre- and post-petition and unpaid bills and caused the Utility to file a interest on certain claims prior to emerging from voluntary petition for relief under the Bankruptcy bankruptcy. The Bankruptcy Court also Code in the Bankruptcy Court on April 6, 2001. authorized the Utility to make certain principal payments on pre-petition secured debt that has While in bankruptcy, the Utility is not allowed to matured. See the Cash Flows section of this pay liabilities incurred before it filed for MD&A for a discussion of the Utility's interest and principal payments made during 2002.

10

Since filing for bankruptcy, the Utility has been On January 1, 2003, the IOUs, including the accruing interest on its pre-petition liabilities at Utility, resumed procuring electricity to meet the required rates included in the Utility's their customers' net open position under proposed plan of reorganization. As a result, the California Senate Bill (SB) 1976. For discussion payment of such interest did not have a material of the requirements contained in SB 1976, see adverse impact on its financial condition or "Regulatory Matters" section of the MD&A and results of operations. Note 2 of the Notes to the Consolidated Financial Statements.

The Utility will continue to accrue interest on its pre-petition liabilities at the required rates in See Note 2 of the Notes to the Consolidated 2003. However, due to the uncertainty of the Financial Statements for further discussion of the ultimate outcome of the bankruptcy proceedings, California energy crisis, the Utility's voluntary the Utility is not able to estimate the amount of petition for relief under the Bankruptcy Code, interest that will be paid in 2003. and the status of the Chapter 11 confirmation hearings.

The Utility and PG&E Corporation have jointly filed a proposed plan of reorganization (Plan) PG&E NEG that, if approved, would enable the Utility to PG&E NEG has been significantly impacted by emerge from bankruptcy. The Utility Plan, and adverse changes in the energy markets in 2002.

an alternative plan proposed by the CPUC and New generation came online while the demand the OCC are currently moving through the for power was dropping. This oversupply and Chapter 11 process. In November 2002, the reduced demand resulted in low spark spreads Bankruptcy Court began the confirmation trial to (the net of power prices less fuel costs) and determine which plan, if any, the Bankruptcy depressed operating margins. These changes in Court will confirm. The Bankruptcy Court has the power industry have had a significant scheduled hearing dates through the end of negative impact on the financial results and March 2003. PG&E Corporation and the Utility liquidity of PG&E NEG. Before July 31, 2002, are not able to predict the ultimate outcome of most of the various debt instruments of PG&E the Utility's bankruptcy proceedings, including NEG and its affiliates carried investment grade which plan, if any, the Bankruptcy Court may credit ratings assigned by Standard & Poor's confirm.

Ratings Group (S&P) and Moody's Investors Both the Plan and the alternative plan propose Service (Moody's). Since July 31, 2002, these issuing new debt as part of the reorganization. credit rating agencies have downgraded all of PG&E Corporation and the Utility have incurred, PG&E NEG's debt facilities to below investment and will continue to incur throughout the grade.

reorganization process, legal, accounting, trustee, PG&E NEG is currently in default under various and other fees associated with the debt issuance.

recourse debt agreements and guaranteed equity In addition, PG&E Corporation and the Utility commitments totaling approximately $2.9 billion.

have incurred and will continue to incur In addition, other PG&E NEG subsidiaries are in consulting fees for assistance with the default under various debt agreements totaling implementation of either plan. The majority of approximately $2.5 billion, but this debt is non-the debt issuance fees and consulting expenses recourse to PG&E NEG. On November 14, 2002, incurred thus far have been expensed and are PG&E NEG defaulted on the repayment of its included in Reorganization Professional Fees and

$431 million 364-day tranche of its corporate Expenses in the Consolidated Statements of revolving credit facility (Corporate Revolver).

Operations, though a small amount has been This resulted in a default under the two-year capitalized. The Utility will continue to expense tranche of the Corporate Revolver, which had an costs associated with the reorganization process outstanding balance of $273 million at that do not specifically relate to certain services December 31, 2002, the majority of which associated with issuing new debt.

supports outstanding letters of credit. The default under the Corporate Revolver also constitutes a 11

cross-default under PG&E NEG's (amounts particular, the Credit Agreement limits PG&E outstanding at December 31, 2002): (1) Senior Corporation's ability to make investments in Notes ($1 billion), (2) guarantee of its turbine PG&E NEG and its subsidiaries from existing revolving credit facility (Turbine Revolver) cash to 75 percent of the net cash tax savings

($205 million), and (3) equity commitment (less certain costs and expenses) actually guarantees for GenHoldings 1, LLC's (Gen received by PG&E Corporation as a result of Holdings) credit facility ($355 million), La Paloma certain sales and debt restructuring transactions credit facility ($375 million) and Lake Road credit of PG&E NEG and its subsidiaries. See further facility ($230 million). In addition, on details in "PG&E Corporation-Debt Financing" November 15, 2002, PG&E NEG failed to pay a below.

$52 million interest payment due under the If the negotiations with PG&E NEG's lenders Senior Notes. PG&E NEG does not currently prove unsuccessful and if lenders exercise their have sufficient cash to meet its financial default remedies and PG&E NEG is forced to obligations and has ceased making payments on seek protection under or is forced into a its debt and equity commitments.

proceeding under the Bankruptcy Code, PG&E NEG and its subsidiaries are restructuring management does not expect the liquidity their operations to increase cash, reduce financial constraints at PG&E NEG and its subsidiaries will obligations, dispose of merchant plant facilities, affect the financial condition of PG&E and decrease energy trading operations. PG&E Corporation or the Utility.

NEG's objective is to limit its asset trading and Asset transfers, sales and abandonments, liquidity risk management activities to only what is issues, and restructuring activities have resulted necessary for energy management services to in substantial charges to earnings in 2002. In facilitate the transition of PG&E NEG's merchant addition, PG&E NEG and its subsidiaries expect generation facilities through their sale, transfer or to incur additional substantial charges to abandonment. PG&E NEG will then further earnings in 2003 primarily related to:

reduce and transition to only retain limited capabilities to ensure fuel procurement and

• The reduction in energy trading activities; power logistics for PG&E NEG's retained

• The possible settlement of tolling independent power plant operations. These arrangements, see discussion of tolling restructuring activities have caused material agreements in this MD&A under charges to earnings in 2002, and are anticipated Commitments and Capital to cause substantial additional charges to Expenditures-Tolling Agreements; earnings in 2003.

• Charges related to the adoption of PG&E NEG, its subsidiaries and their lenders are Statement of Financial Accounting engaged in discussions regarding restructuring of Standards (SFAS) No. 143, "Accounting for these commitments. If a restructuring agreement Asset Retirement Obligations" (see is not reached and the lenders exercise their discussion in this MD&A under default remedies, or if the financial commitments Accounting Pronouncements issued but are not restructured, PG&E NEG and certain of not yet adopted);

its subsidiaries may be compelled to seek

• A possible settlement under the Attala protection under or be forced involuntarily into tolling agreement and related lease (see proceedings under the Bankruptcy Code. discussion below in Impairments, Write-offs, and Other Charges);

PG&E Corporation is participating with PG&E NEG, its subsidiaries and their lenders in

• Potential conversion of existing debt and negotiations to restructure PG&E NEG's and its equity funding commitments to new subsidiaries' commitments. However, under the discounted obligations, including potential terms of its credit agreement, PG&E Corporation write-offs of deferred financing costs; and is limited as to the amount and conditions under

• Further restructuring costs.

which it can provide cash to PG&E NEG. In 12

Impairments, Write-offs,, and Other Charges generating projects. Although PG&E NEG has The following table outlin( !s the pre-tax ch~xarges guaranteed GenHoldings' obligation to make for impairments, write-offs esand other charges equity contributions of up to $355 million, PG&E

,iand other carded

NEG notified the GenHoldings' lenders that it that PG&E NEG and its sul Fourth Yes Ended would not make further equity contributions on Quarter December 31, behalf of GenHoldings. In November and (in mElons) 2002 2002 December 2002, the lenders executed waivers Impairment of GenHoldings and amendments to the credit agreement under projects $1,147 $1,147 which they agreed to continue to waive until Impairment of Lake Road March 31, 2003, the default caused by and La Paloma projects 452 452 GenHoldings' failure to make equity Impairment of Mantua contributions. In addition, certain of these Creek project 279 279 lenders have agreed to increase their loan Impairment of Turbines &

Other Related Equipment commitments to an amount sufficient to provide:

costs 30 276 (1) the funds necessary to complete construction Termination of Interest Rate of the Athens, Covert and Harquahala facilities; Swaps on Lake Road, La and (2) additional working capital facilities to Paloma, and enable each project, including Millennium, to GenHoldings projects 189 189 timely pay for its fuel requirements and to Impairment of Dispersed Generation 88 118 provide its own collateral to support natural gas Impairment of Goodwill - 95 pipeline capacity reservations and independent Impairment of Project transmission operator requirements. The Development Costs 57 76 November and December increased loan Impairment of Southaven commitments rank equally with each other but Loan 74 74 are senior to amounts loaned through and Impairment of Prepaid including the October credit extension.

Rents related to the Attala lease 43 43 In consideration of the lenders' forbearance and Impairment of Kentucky additional funding, PG&E NEG and GenHoldings Hydro project 18 18 have agreed to cooperate with any reasonable Total Pre-tax Impairments, proposal by the lenders regarding disposition of Write-offs, and Other the equity in or assets of any or all of the Charges $2,377 $2,767 GenHoldings subsidiaries holding the Athens, Discontinued Operations - Covert, Harquahala, and Millennium projects in Pre-tax Loss on disposal of USGen New England, connection with the restructuring of PG&E NEG's Inc. 1,123 1,123 and its subsidiaries' financial commitments to Pre-tax loss on disposal of such lenders. The amended credit agreement ET Canada 25 25 provides that an event of default will occur if the Total Pre-tax Charges $3,525 $3,915 Athens, Covert, Harquahala, and Millennium projects are not transferred to the lenders or their Impairmentof GenHolMrings I LLC Projects: designees on or before March 31, 2003. Such a GenHoldings, a subsidiary of PG&E NEG, is default would trigger lender remedies, including obligated under its credit I'acility to make equity the right to foreclose on the projects. Under the contributions to fund cons truction of the Athens, waiver, PG&E NEG has re-affirmed its guarantee Covert and Harquahala ge nerating projects. This of GenHoldings' obligation to make equity credit facility is secured b) r these projects in contributions of approximately $355 million to addition to the Millennium generating facility. these projects. Neither PG&E NEG nor GenHoldings defaulted un der its credit GenHoldings currently expects to have sufficient agreement in October 200: 2 by failing to make funds to make this payment. The requirement to equity contributions to fur id construction draws pay $355 million remains an obligation of PG&E for the Athens, Covert and i Harquahala 13

NEG that would survive the transfer of the the PG&E NEG subsidiaries nor PG&E NEG have projects. sufficient funds to make these payments. The requirement to make the payments will remain In accordance with the provisions of SFAS an obligation of PG&E NEG that would survive No. 144 "Accounting For the Impairment or the transfer of the projects.

Disposal of Long-Lived Assets," the long-lived assets of GenHoldings at December 31, 2002 In accordance with the provisions of SFAS were tested for impairment. As a result of the No. 144, the long-lived assets of the Lake Road test, the assets were determined to be impaired and la Paloma project subsidiaries at and were written-down to fair value. Based on December 31, 2002, were tested for impairment.

the current estimated fair value of these assets, As a result of the test, these assets were GenHoldings recorded a pre-tax loss from determined to be impaired and were written impairment of $1.147 billion in the fourth quarter down to fair value. Based on the current of 2002. estimated fair value of these assets, the Lake Road and La Paloma project subsidiaries Impairment of Lake Road and La Paloma recorded a pre-tax loss from impairment of Projects: On November 14, 2002, PG&E NEG approximately $186 million and $266 million, defaulted under its equity commitment respectively, in the fourth quarter of 2002.

guarantees for the Lake Road and the La Paloma credit facilities. As of December 4, 2002, PG&E Impairment of Mantua Creek Project The NEG and certain of its subsidiaries entered into Mantua Creek project is a nominal 897 megawatt agreements with respect to each of the Lake (MW) combined cycle merchant power plant Road and La Paloma generating projects located in the Township of West Deptford, New providing for (1) funding of construction costs Jersey. Construction began in October 2001 and required to complete the La Palorna facility; and the project was 24 percent complete as of (2) additional working capital facilities to enable October 31, 2002. Due to liquidity concerns, each subsidiary to timely pay for its fuel PG&E NEG could no longer provide equity requirements and to provide its own collateral to contributions to the project and efforts to sell the support natural gas pipeline capacity reservations project were unsuccessful. Beginning in the and independent transmission system operator fourth quarter of 2002, contracts with vendors requirements, as well as for general working were suspended or terminated to eliminate an capital purposes. Lenders extending new credit increase in project costs. In December 2002, the under these agreements have received liens on project provided notices of termination to the the projects that are senior to the existing Pennsylvania, New Jersey, Maryland Independent lenders' liens. These agreements provide, among System Operator (PJM), and other significant other things, that the failure to transfer right, title counterparties. With all significant contracts and interest in, to and under the Lake Road and terminated, PG&E NEG's subsidiary will abandon La Paloma projects to the respective lenders by this project in early 2003. PG&E NEG's subsidiary June 9, 2003, will constitute a default under the has written off the capitalized development and agreements. The failure to transfer the facilities construction costs of $257 million at would entitle the lenders to accelerate the new December 31, 2002. In addition, PG&E NEG has indebtedness and exercise other remedies. recorded an accrual of $22 million for charges and associated termination costs at December 31, The Lake Road and La Paloma projects have 2002.

been financed entirely with debt. PG&E NEG has guaranteed the repayment of a portion of the Impairment of Turbines and Otber Related project subsidiary debt of approximately Equipment. To support PG&E NEG's electric

$230 million for Lake Road and $375 million for generating development program, PG&E NEG La Paloma, which amounts represent the subsidiaries had contractual commitments and subsidiaries' equity contribution in the projects. options to purchase a significant number of The lenders have demanded the immediate combustion turbines and related equipment.

payment of these equity contributions. Neither PG&E NEG subsidiaries' commitment to purchase 14

combustion turbines and related equipment amount of $9.5 million expected to be paid in exceeded the new planned development July 2003.

activities discussed herein. In the second quarter Termination of Interest Rate Swaps on Lake of 2002, these PG&E NEG subsidiaries Road, La Paloma and GenHoldingsProjects:

recognized a pre-tax charge of $246 million. The As a result of the Lake Road and La Paloma charge consisted of the impairment of the project subsidiaries' failure to make required previously capitalized costs associated with prior equity payments under interest rate hedge payments made under the terms of the turbine contracts entered into by them, the and equipment contracts in the amount of counterparties to such interest rate hedge

$188 million and an accrual of $58 million for contracts have terminated the contracts.

future termination payments required under the Settlement amounts due from the Lake Road and turbine and related equipment contracts. In La Paloma project subsidiaries in connection with addition, at that time, the PG&E NEG subsidiaries such terminated contracts are, in the aggregate, retained capitalized prepayment costs associated

$61 million and $78 million, respectively. Further, with three development projects that were to be as a result of GenHoldings' failure to make further developed or sold. In the fourth quarter required payments under interest rate hedge of 2002, these PG&E NEG subsidiaries incurred contracts entered into by GenHoldings, the an additional pre-tax charge of $30 million for counterparties to such interest rate hedge the write-off of prior turbine prepayments contracts terminated the contracts during associated with the impairment of the remaining December 2002. Settlement amounts due by development projects as discussed below.

GenHoldings in connection with such terminated In November 2002, subsidiaries of PG&E NEG contracts are, in the aggregate, approximately reached agreement with General Electric $50 million. The Lake Road and La Paloma Company (GEC) to terminate its master turbine project subsidiaries and GenHoldings incurred a purchase agreement and with General Electric pre-tax charge to earnings in the fourth quarter International, Inc. (GEII) to terminate its master of 2002 for these amounts totaling $189 million.

long-term service agreement. GEC and GEII have Impairment of Dispersed Generation agreed to reduce the termination fees from PG&E NEG is seeking a buyer for PG&E approximately $34 million to approximately Dispersed Generation, LLC, Plains End, LLC,

$22 million and to defer payment of the reduced Dispersed Properties, LLC and 100 percent of the fees to December 31, 2004. The costs to capital stock of Ramco Inc, (collectively, referred terminate this contract were accrued for in the to as Dispersed Gen Companies or Dispersed second quarter of 2002 as discussed above.

Generation). In accordance with the provisions Also in November 2002, Mitsubishi Power of SFAS No. 144, the long-lived assets of the Systems, Inc. (MPS) notified PG&E NEG's Dispersed Gen Companies were tested for subsidiary that it was terminating the turbine impairment. As a result of the test, these assets purchase agreement for failure to pay past due were determined to be impaired and were amounts and failure to collateralize PG&E NEG's written down to fair value. Based on the current guarantee. While PG&E NEG's subsidiary has estimated fair value (based on the estimated disputed that such amounts were due before proceeds) of a sale, Dispersed Generation January and July 2003 and has asserted that a recorded a pre-tax loss from impairment of breach under PG&E NEG's guarantee did not $88 million in the fourth quarter of 2002. This is give rise to a breach of the turbine purchase in addition to a pre-tax loss from impairment of agreement, neither PG&E NEG nor its subsidiary $30 million that was recorded in the third quarter intends to contest the termination. The costs to of 2002, which related to certain equipment terminate this contract were accrued for in the (turbines, generators, transformers, etc.) that was second quarter of 2002, as discussed above. On purchased and/or refurbished and held for future January 31, 2003, a termination payment of expansion at current Dispersed Generation

$4.5 million was made with the remaining facilities.

15

Impairmentof Goodwilk SFAS No. 142 Impairment of Soutbaven Power LLC Loan "Goodwill and Other Intangible Assets," requires Recefiable PG&E ET signed a tolling that goodwill be reviewed at least annually for agreement with Southaven Power LLC impairment. Due to significant adverse changes (Southaven) dated June 1, 2000, pursuant to within the national energy markets, PG&E NEG which PG&E ET was required to provide credit and its subsidiaries elected to test its goodwill for support that meets certain requirements set forth possible impairment in the third quarter of 2002. in the agreement. PG&E ET satisfied this Based upon the results of the fair value test, obligation by providing an investment-grade PG&E NEG and it subsidiaries recognized a guarantee from PG&E NEG. The original goodwill impairment loss of $95 million in the maximum amount of the guarantee was third quarter of 2002. The fair value of the $250 million. However, this amount was reduced segment was estimated using the discounted by approximately $74 million, the amount of a cash flows method. At December 31, 2002, there subordinated loan that PG&E ET made to was no goodwill remaining at PG&E NEG and its Southaven on August 31, 2002.

subsidiaries.

Southaven has advised PG&E ET that it believes Impairment of Development Costs: In the an event of default under the tolling agreement second quarter of 2002, PG&E NEG project has taken place with respect to the obligation for subsidiaries recognized an impairment loss a guarantee because PG&E NEG is no longer related to the capitalized costs associated with investment-grade as defined in the agreement certain development projects. These PG&E NEG and because PG&E Er has failed to provide, subsidiaries analyzed the potential future cash within 30 days from the downgrade, substitute flow from those projects that it no longer credit support that meets the requirements of the anticipated developing and recognized an agreement. Under the tolling agreement, impairment of the asset value it was carrying for Southaven has the right to terminate the those projects. The aggregate pre-tax impairment agreement and seek a termination payment. In charge recorded by these PG&E NEG subsidiaries addition, PG&E ET has provided Southaven with for its development assets (excluding associated a notice of default with respect to Southaven's equipment) was $19 million recorded in the performance under the tolling agreement. If this second quarter of 2002. At that time, these PG&E default is not cured, PG&E ET has the right to NEG subsidiaries continued to develop or terminate the agreement and seek recovery of a planned to sell three additional projects. These termination payment. On February 4, 2003, subsidiaries have ceased developing these PG&E ET provided a notice of termination.

projects and sought to sell the development Southaven has objected to the notice and has assets. To date, these subsidiaries have been filed suit in connection with this matter. PG&E unsuccessful in selling these projects and have ET has recorded an impairment of the loan tested the capitalized costs associated with the receivable due to the uncertainty associated with projects for impairment at December 31, 2002. the recoverability of the loan, which was Based upon the results of these tests, an subordinate to the senior debt of the project and additional aggregate pre-tax impairment charge reliant upon operations of the plant under the of approximately $57 million was recorded by terms of the tolling agreement.

these subsidiaries for their development assets (excluding associated equipment costs as Impairment of PrepaidRents on Attala discussed above) in the fourth quarter of 2002. Lease: On May 7, 2002, Attala Generating While these subsidiaries have impaired all of Company LLC (Attala Generating), an indirect their development projects, they have not wholly owned subsidiary of PG&E NEG, abandoned the permits or rights to these completed a $340 million sale and leaseback projects. It is anticipated that these permits and transaction whereby it sold and leased back its rights will be abandoned for all development approximately 526 MW generation facility located projects in 2003. in Mississippi to a third-party special purpose entity.

PG&E NEG has provided a $300 million after such failure to provide security. Upon the guarantee to support the payment obligations of occurrence of an event of default under the another indirect wholly owned subsidiary, Attala lease, the lessor would be entitled to exercise Energy Company LLC (Attala Energy) under a various remedies, including termination of the tolling agreement entered into with Attala lease and foreclosure of the assets securing the Generating. The payments under the 25-year lease. At December 31, 2002, Attala Generating term tolling agreement provide Attala wrote-off prepaid rental payments of $43 million Generating, as lessee, with sufficient cash flows due to the uncertainty of future cash flows during the term of the tolling agreement to pay associated with the lease.

rent under a 37-year lease and certain other operating costs. Due to current energy market Impairment of Kentucky Hydro Project.

conditions, Attala Energy is unable to make the The Kentucky Hydro Generating Project consists payments under the tolling agreement and failed of two run-of-river hydroelectric power plants to make the required payment due on located in Kentucky on the Ohio River. The November 22, 2002, to Artala Generating. Failure project negotiated a turnkey, fixed price contract to cure this payment default constituted an event with VA Tech MCE Corporation (VA Tech) and of default under the tolling agreement as of issued a limited notice to proceed in November 27, 2002. Further, PG&E NEG's failure August 2001. Beginning in the fourth quarter of to pay maturing principal under its Corporate 2002, all work on the project was suspended Revolver on November 14, 2002, became an except for minimal expenditures to maintain the event of default Linder the tolling agreement FERC licenses. The termination cost due to VA upon Attala Energy's failure to replace the PG&E Tech of approximately $14 million was fully NEG guarantee by December 16, 2002. On paid. VA Tech terminated the contract effective December 31, 2002, the tolling agreement December 6, 2002. As part of the settlement of terminated following notice of termination given PG&E NEG subsidiary's partnership arrangement, by Attala Generating. The parties are currently this subsidiary assigned its partnership interest to determining the termination payment, if any, that the original developer, W.V. Hydro, on Attala Energy would owe Attala Generating. February 7, 2003. PG&E NEG has written-off the Despite the termination of the tolling capitalized development and construction costs agreements, Attala Energy remains obligated to and provided for all termination costs by provide an acceptable guarantee or collateral to recording a pre-tax charge of $18 million at secure its obligations under the tolling December 31, 2002.

agreement, including the payment of any termination payment that may be determined to Asset Held For Sale - U.S. Gen New England.

be due. Consistent with its previously announced strategy to dispose of certain merchant assets, in No default has occurred under the related lease December 2002, the Board of Directors of PG&E and Attala Generating timely made the Corporation approved management's plan for the

$22.2 million lease payment due on January 2, proposed sale of USGen New England Inc.

2003. However, the lease provides that failure to (USGenNE). Under the provisions of SFAS replace the tolling agreement with a satisfactory No. 144, the equity of USGenNE has been replacement tolling agreement within 180 days accounted for as an asset held for sale at after the first default under the tolling agreement, December 31, 2002. This requires that the assets which occurred on November 27, 2002, will be recorded at the lower of fair or book value.

constitute an event of default under the lease. Based on the current estimated fair value (based After the termination payment has been on the estimated proceeds) of a sale of determined in accordance with the tolling USGenNE, a pre-tax loss of $1.1 billion, with no agreement and if Attala Energy or PG&E NEG tax benefits associated with the loss, was both fail, or have failed, to provide security as recorded in the fourth quarter of 2002. It is required by the tolling agreement, the time anticipated that the sale of the USGenNE assets period would not extend beyond the 60oh day will occur during 2003. This loss on sale, as well 17

as the operating results from USGenNE, have by the end of February or early March 2003. In been reported as discontinued operations in the accordance with the provisions of SFAS No. 144, financial statements of PG&E NEG and the equity of ET Canada has been classified as subsidiaries at December 31, 2002. assets held for sale and will be reflected as discontinued operations in the financial Assets Held for Sale - ET Canadal In statements of PG&E NEG and subsidiaries as of December 2002, the proposed sale of PG&E December 31, 2002.

Energy Trading, Canada Corporation (ET Canada) to Seminole Gas Company Limited was COALMTMENTS AND CAPITAL approved. Based upon the sales price, PG&E EXPENDITuRS Energy Trading Holdings Corporation, the direct owner of the shares of ET Canada, recorded a The following table provides information about

$25 million pre-tax loss, with no tax benefits PG&E Corporation, the Utility and PG&E NEG's associated with the loss, on the disposition of ET contractual obligations and commitments at Canada. The transaction is anticipated to close December 31, 2002.

(Dolars in mallons) 2003 2004 2005 2006 2007 Thereafter Utility:

Power purchase agreements ............. ...... $1,701 $1,544 $1,446 $1,377 $8,492 .$1,9 Natural gas supply and transportation ....... 595 138 83 26 10 Nuclear fuel ......................... 59 50 12 13 14 65 Other Commitments................... 60 45 39 24 11 11 Long-term debt:

Liabilities not subject to compromise:

Fixed rate principal obligations ........ 281 310 290 _ _ 2,139 Average interest rate ................ 6.25% 6.25% 5.88%/ _ _ 7.25%

Liabilities subject to compromise:

Fixed rate principal obligations ........ 173 54 696 1 1 261 Average interest rate ................ 7.400% 7.51% 9.56% 9.45% 9.45% 5.95%

7.90 Percent Deferrable Interest Subordinatv Debentures ................... 300 Variable rate principal obligations ...... 349 )55 Rate reduction bonds .................. 290 )0 290 290 290 62.9 Average interest rate ................. 6.36% 6.2 i2% 6.42% 6.44% 6.48%

PG&E NEG Fuel supply and natural gas transportation agre( 105 C91 91 88 75 380 Power purchase agreement .............. 217 2220 220 220 225 1,140 Operating leases ...................... 70 79 79 81 84 807 Long-Term Service Agreements ........... 41 7 7 7 7 36 Payment in lieu of taxes ................ 28 21 14 16 17 97 Construction commitments............. 237 Tolling agreements .................... 62 62 62 62 62 482 Long-term debt:

Fixed rate obligations............... 6 - 250 250 Variable rate obligations ............... 86 3 60 52 4 11 Average interest rate ................. 6.41%. 6.c i7% 6.92% 7.33% 7.31% 7.10%

PG&E Corporation:

Long-term debt:

Fixed rate obligations (9.50%o Convertible Subordinated Notes) ................ 280 Average interest rate ................... _ _ _ _ - 9.50%

Variable rate (l) .................... -- - 842 - -

(11 $720 million outstanding at December 31, 2002, with 4 percent interest compounded yields value of $842 million at maturity.

18

Utffity party producers under the power purchase contracts.

The Utility's contractual commitments include natural gas supply and transportation Operating Leases -Various subsidiaries of agreements, purchase power agreements PG&E NEG entered into several operating lease (including agreements with QFs, irrigation agreements for generating facilities and office districts and water agencies, bilateral power space. Lease terms vary between 3 and 48 years.

purchase contracts, and renewable energy contracts), nuclear fuel agreements, operating In November 1998, USGenNE entered into a leases and other commitments. $479 million sale-leaseback transaction whereby the subsidiary sold and leased back a pumped The Utility's commitments under financing storage station under an operating lease.

arrangements include obligations to repay first and refunding mortgage bonds, senior notes, On May 7, 2002, Attala Generating completed a medium-term notes, pollution control loan $340 million sale and leaseback transaction agreements, Deferrable Interest Subordinated whereby it sold and leased back its facility to a Dedentures, lines of credit, letters of credit, third party special purpose entity. The related floating rate notes, and commercial paper. lease is being accounted for as an operating lease. See discussion above for further PG&E Funding LLC, a wholly owned subsidiary information relating to the Attala lease of the Utility is also obligated to make scheduled agreement.

principal payments on its rate reduction bonds.

Operating lease expense amounted to For further detailed discussion of the Utility's $78 million, $54 million, and $70 million in 2002, contractual commitments and obligations, see 2001, and 2000, respectively.

Notes 4, 5, and 16 of the Notes to the Consolidated Financial Statements. Long-Term Service Agreements -Various subsidiaries of PG&E NEG have entered into PG&E NIEG long-term service agreements for the maintenance and repair of certain combustion PG&E NEG subsidiaries have the following turbine or combined-cycle generating plants.

contractual commitments: These agreements are for periods up to 18 years.

Fuel Supply and Transportation Payments in Lieu of Property Taxes -

Agreements -PG&E NEG, through its various Various subsidiaries of PG&E NEG have entered subsidiaries, has entered into gas supply and into certain agreements with local governments firm transportation agreements with a number of that provide for payments in lieu of property pipelines and fuel transportation services. Under taxes for some of its generating facilities.

these agreements, PG&E NEG's subsidiaries must make specified minimum payments each month. ConstructionCommitments -Various subsidiaries of PG&E NEG currently have four Power PurchaseAgreements - USGenNE projects (Athens, Covert, La Paloma, and assumed rights and duties under several power Harquahala) under construction. PG&E NEG's purchase contracts with third party independent construction commitments are generally related power producers as part of the acquisition of the to the major construction agreements including New England Electric System assets. As of the construction and other related contracts.

December 31, 2002, these agreements provided Certain construction contracts also contain for an aggregate of approximately 800 MW of commitments to purchase turbines and related capacity. USGenNE is required to pay New equipment.

England Power Company amounts due to third-19

Tolling Agreements - PG&E ET entered into PG&E GTN and PG&E ET have terminated the tolling agreements with several counterparties arrangements pursuant to which PG&E GTN allowing PG&E NEG the right to sell electricity provided guarantees on behalf of PG&E ET such generated by facilities owned and operated by that PG&E GTN will provide no new guarantees other parties. Under the tolling agreements, on behalf of PG&E ET.

PG&E NEG, at its discretion, supplies the fuel to the power plants, then sells the plant's output in At January 31, 2003, PG&E Ers estimated the competitive market. Committed payments are exposure not covered by a guarantee (excluding reduced if the plant facilities do not achieve exposure under tolling agreements) was agreed-upon levels of performance. See Tolling approximately $90 million.

Agreements below for additional information relating to these agreements. To date, PG&E ET has met those replacement security requirements properly demanded by Guarantees counterparties and has not defaulted under any of its master trading agreements although one PG&E NEG's and its subsidiaries' guarantees fall counterparty has alleged a default. No demands into four broad categories: have been made upon the guarantors of PG&E ET's obligations under these trading agreements.

. Equity commitments; In the past, PG&E ET has been able to negotiate

• PG&E ET's energy trading and non-trading acceptable arrangements and reduce its overall activities related to PG&E NEG's merchant exposure to counterparties when PG&E ET or its energy portfolio excluding tolling counterparties have faced similar situations.

agreements; There can be no assurance that PG&E ET can continue to negotiate acceptable arrangements in

• Tolling agreements; and the current circumstances. PG&E NEG cannot

• Other guarantees. quantify with any certainty the actual future calls on PG&E El's liquidity. PG&E NEG's and its Equity Commitments: Refer to discussion subsidiaries' ability to meet these calls on their above on impairments under "Market Conditions liquidity will vary with market price volatility, and Business Environment." uncertainty with respect to PG&E NEG's financial condition and the degree of liquidity in the Activities Related to Mercbant Portfolio energy markets. The actual calls for collateral Operations' PG&E NEG and certain will depend largely upon the ability to enter into subsidiaries have provided guarantees to forbearance agreements, and pre- and early-pay approximately 232 counterparties in support of arrangements with counterparties, the continued PG&E ET's energy trading and non-trading performance of PG&E NEG companies under the activities related to PG&E NEG's merchant underlying agreements, whether counterparties energy portfolio in the face amount of have the right to demand such collateral, the

$2.7 billion. Typically, the overall exposure execution of master netting agreements and under these guarantees is only a fraction of the offsetting transactions, changes in the amount of face value of these guarantees, since not all exposure, and other commercial considerations.

counterparty credit limits are fully used at any time. As of January 31, 2003, PG&E NEG and its Tolling Agreements: PG&E ET has entered subsidiaries' aggregate exposure under these into tolling agreements with several guarantees was approximately $82.8 million. The cointerparties under which it, at its discretion, amount of such exposure varies daily depending supplies the fuel to the power plants and then on changes in market prices and net changes in sells the plant's output in the competitive market.

position. In light of the downgrades, some Payments to the counterparties are reduced if the counterparties have sought and others may seek plants do not achieve agreed-upon levels of replacement security to collateralize the exposure performance. The face amount of PG&E NEG's guaranteed by PG&E NEG and its subsidiaries. and its subsidiaries' guarantees relating to PG&E 20 y

E's tolling agreements is approximately replacement security. If PG&E ET was required

$600 million. The tolling agreements currently in to post replacement security and it failed to do place are with: (1) Liberty Electric Power, L.P. so, DTE would have the right to terminate the (Liberty) guaranteed primarily by PG&E NEG and tolling agreement and seek recovery of a secondarily by PG&E GTN for an aggregate termination payment.

amount of up to $150 million; (2) DTE-Georgetown, LLC (DTE) guaranteed by Calpine -The tolling agreement states that on PG&E GTN for up to $24 million; (3) Calpine or before October 15, 2002, Calpine was to have Energy Services, L.P. (Calpine) for which no issued a full notice to proceed under its guarantee is in place; (4) Southaven guaranteed construction contract to its engineering, by PG&E NEG for up to $175 million; and procurement and construction contractor for the (5) Caledonia Generating, LLC (Caledonia) Otay Mesa facility. On October 16, 2002, PG&E guaranteed by PG&E NEG for up to ET asked Calpine to confirm that it had issued

$250 million. this full notice to proceed and Calpine was not able to do so to the satisfaction of PG&E ET.

Liberty -Liberty has provided notice to PG&E Consequently, PG&E ET advised Calpine by ET that the ratings downgrade of PG&E NEG letter dated October 30, 2002, that it was constituted a material adverse change under the terminating the tolling agreement effective tolling agreement requiring PG&E ET to replace November 29, 2002. Calpine has indicated that the guarantee and post security in the amount of this termination was improper and constituted a

$150 million. PG&E ET has not posted such default under the agreement, but has not taken security. Liberty has the right to terminate the any further action.

agreement and seek recovery of a termination payment. Under the terms of the guarantees to Caledonia and Soutbaven New Toling Liberty for the aggregate $150 million, Liberty Agreements -PG&E ET signed a tolling must first proceed against PG&E NEG's agreement with Caledonia dated as of guarantee, and can demand payment under September 20, 2000, pursuant to which PG&E ET PG&E GTN's guarantee only if (1) PG&E NEG is is to provide credit support as defined in the in bankruptcy or (2) Liberty has made a payment tolling agreement. PG&E ET satisfied this demand on PG&E NEG which remains unpaid obligation by providing a guarantee from PG&E five business days after the payment demand is NEG that was investment-grade as defined in the made. In addition, PG&E ET has provided agreement. The amount of the guarantee now notices to Liberty of several breaches of the does not exceed $250 million. By letter dated tolling agreement by Liberty and has advised August 31, 2002, Caledonia advised PG&-E ET Liberty that, unless cured, these breaches would that it believed an event of default under the constitute a default under the agreement. If these tolling agreement had taken place with respect defaults remain uncured, PG&E ET has the right to this obligation as PG&E NEG was no longer to terminate the agreement and seek recovery of investment-grade as defined in the tolling a termination payment. agreement and because PG&E ET had failed to provide, within thirty days from the downgrade DTE -By letter dated October 14, 2002, DTE substitute credit support that met the provided notice to PG&E ET that the downgrade requirements of the tolling agreement. Caledonia of PG&E GTN constituted a material adverse has the right to terminate the agreement and change under the tolling agreement between seek a termination payment. In addition, PG&E PG&E ET and DTE and that PG&E ET was ET has provided Caledonia with a notice of required to post replacement security within ten default respecting Caledonia's performance days. By letter dated October 23, 2002, PG&E ET under the tolling agreement concerning the advised DTE that because there had not been a inability of the facility to inject its output into the material adverse change with respect to PG&E local grid. Caledonia has not cured this default GTN within the meaning of the tolling and on February 4, 2003, PG&E ET provided a agreement, PG&E ET was not required to post notice of termination.

21

PG&E ET signed a tolling agreement with mandatory arbitration. The dispute resolution Southaven dated as of June 1, 2000, under which process could take as long as six months to PG&E ET is required to provide credit support as more than a year to complete. To the extent that defined in the agreement. PG&E ET satisfied this PG&E ET did not pay these damages, the obligation by providing an investment-grade counterparties could seek payment under the guarantee from PG&E NEG as defined in the guarantees for an aggregate amount not to tolling agreement. The amount of the guarantee exceed $600 million. PG&E NEG is unable to is approximately $175 million. By letter dated predict whether counterparties will seek to August 31, 2002, Southaven advised PG&E ET terminate their tolling agreements. PG&E NEG that it believed an event of default under the does not currently expect to be able to pay any tolling agreement had taken place as PG&E NEG termination payments that may become due.

was no longer investment-grade as defined in the tolling agreement and because PG&E Er had Other Guarantees failed to provide, within thirty days from the downgrade, substitute credit support that met the PG&E NEG has provided guarantees related to requirement of the tolling agreement. Southaven other obligations by PG&E NEG companies to has the right to terminate the agreement and counterparties for goods or services. PG&E NEG seek a termination payment. In addition, PG&E does not believe that it has significant exposure ET has provided Southaven with a notice of under these guarantees. The most significant of default respecting Southaven's performance these guarantees relate to performance under under the tolling agreement concerning the certain construction and equipment procurement inability of the facility to inject its output into the contracts. In the event PG&E NEG is unable to local grid. Southaven has not cured this default provide any additional or replacement security and on February 4, 2003, PG&E ET provided a which may be required as a result of rating notice of termination. downgrades, the counterparty providing the goods or services could suspend performance or On February 7, 2003, Southaven filed emergency terminate the underlying agreement and seek petitions to compel arbitration or alternatively, a recovery of damages. These guarantees represent temporary restraining order and preliminary guarantees of subsidiary obligations for injunction with the Circuit Court for Montgomery transactions entered into in the ordinary course County, Maryland. The Court has denied the of business. Some of the guarantees relate to the relief requested and has set the matter for construction or development of PG&E NEG's hearing on February 27, 2003. power plants and pipelines. These guarantees are described below.

PG&E ET is not able to predict whether the counterparties will seek to terminate the PG&E NEG has issued guarantees for the agreements or whether the Court will grant the performance of the contractors building the requested relief. Accordingly, it is not able to Harquahala and Covert power projects for up to predict whether or the extent to which these $555 million. Any exposure under the guarantees proceedings will have a material adverse effect for construction completion is mitigated by on PG&E NEG's financial condition or results of guarantees in favor of PG&E NEG from the operation. constructor and equipment vendors related to performance, schedule, and cost. The constructor Under each tolling agreement determination of and various equipment vendors are performing the termination payment is based on a formula under their underlying contracts.

that takes into account a number of factors including market conditions such as the price of PG&E NEG has issued $100 million of guarantees power and the price of fuel. In the event of a to the constructor of the Harquahala and Covert dispute over the amount of any termination projects to cover certain separate cost-sharing payment that the parties are unable to resolve by arrangements. Failure to perform under those negotiation, the tolling agreement provides for separate cost-sharing arrangements or the related 22

guarantees would not have an impact on the wholly owned subsidiary, Attala Energy, has constructor's obligations to complete the entered into with Attala Generating. See Harquahala and Covert projects pursuant to the discussion above under "Impairment of Prepaid construction contracts. However, in the event Rents on Attala Lease," for additional discussion that the construction contractor incurs certain of this guarantee.

un-reimbursed project costs or cost overruns, the contractor could assert a claim against PG&E In addition to those discussed above, PG&E NEG NEG's subsidiary or PG&E NEG under its has guarantees for commitments undertaken by guarantees. PG&E NEG believes that no claim PG&E NEG or subsidiaries in the ordinary course can be validly asserted by the construction of business for services such as facility and contractor as of the date hereof. equipment leases, ash disposal rights, and surety bonds.

PG&E NEG has provided a $300 million guarantee to support a tolling agreement that a Credit Facility Summary:

PG&E NEG has the following credit facilities outstanding at January 31, 2003:

Total Bank (in millions) Commitment Balance PG&E NEG Inc. - Tranche A (2 year facility) (a) .... $264 $264 PG&E NEG Inc. - Tranche B (364 day facility) (a) ..... 431 431 PG&E ETH and Subsidiaries - Facility One ............ 35 34 PG&E ETH and Subsidiaries - Facility Two............ 19 19 PG&E Generating LLC .......................... 7 7 USGen New England ........................... 100 88 PG&E GTC and Subsidiaries ...................... 125 53 Total ....................................... $981 $896 (a) PG&E NEG is currently in default on both its Tranche A and Tranche B credit facility.

PG&E CORPORATION principal and interest totaling $607 million to the GECC portion of the debt.

Due to the Utility's deteriorating liquidity and financial condition during the California energy On October 18, 2002, PG&E Corporation entered crisis in 2000, PG&E Corporation refinanced its into a Second Amended Credit Agreement debt obligations through a credit agreement (Credit Agreement) with the remaining lenders (Original Credit Agreement) with General Electric for a total amount of $720 million. Of the total Capital Corporation (GECC) and Lehman amount secured under the Credit Agreement, Commercial Paper Inc. (LCPT) in 2001. The $420 million covered amounts retained under the proceeds of this refinancing were used to pay prior credit agreement and $300 million commercial paper, borrowings under PG&E represented new loans (New Loans and Corporation's long-term revolving credit facility, collectively referred to as the Loans). These New and a fourth quarter 2000 dividend to Loans were released from a separate escrow shareholders. During 2002, PG&E Corporation account to PG&E Corporation on January 17, negotiated new terms to amend the Original 2003, concurrent with a funding fee payment of Credit Agreement. In August 2002, PG&E $9 million.

Corporation made a voluntary prepayment of 23

All obligations of PG&E Corporation under the to 75 percent of the net cash tax savings Credit Agreement are secured by a perfected actually received by PG&E Corporation first-priority security interest in the outstanding from certain PG&E NEG transactions after common stock of the Utility and all proceeds October 1, 2002) in connection with thereof. With respect to 35 percent of such certain sales and debt restructuring common stock pledged for the benefit of the transactions of PG&E NEG and its lenders, the lenders have customary rights of a subsidiaries; secured creditor, provided that certain regulatory

• PG&E Corporation to make investments approvals may be required in connection with funded from existing cash, and to pay any foreclosure on such stock. With respect to obligations of PG&E NEG and its the remaining 65 percent, such common stock subsidiaries (including, without limitation, has been pledged for the benefit of the lenders, any obligations for which PG&E but the lenders have no ability to control such Corporation becomes a surety or a common stock under any circumstances and do guarantor) up to a cumulative amount not not have any of the typical rights and remedies to exceed $15 million; of a secured creditor. However, the lenders do have the right to receive any cash proceeds

• PG&E NEG LLC, PG&E NEG, or their received upon a disposition of such common respective subsidiaries to grant liens or stock. incur debt;

• PG&E Corporation and the Utility to All obligations of PG&E Corporation under the consummate the transactions Credit Agreement continue to be secured by a contemplated in the Utility's Plan; and perfected first priority security interest in 100 percent of the equity interests in PG&E NEG . PG&E Corporation to spin off 100 percent LLC and 100 percent of the common stock of of the equity interests in PG&E NEG LLC PG&E NEG and all proceeds thereof. and 100 percent of the common stock of PG&E NEG, and all proceeds thereof, with The Credit Agreement limits the ability of PG&E the consent of lenders holding more than Corporation and some of its subsidiaries to grant 50.1 percent of the aggregate outstanding liens, consolidate, merge, purchase or sell assets, principal amount of the Loans.

declare or pay dividends, incur indebtedness, or make advances, loans, and investments. In The Credit Agreement provides for stated events addition, PG&E Corporation may not use the of default and events requiring mandatory proceeds of the New Loans to make investments prepayment of the Loans. See Note 4 of the in PG&E NEG LLC or PG&E NEG, or any of their Notes to the Consolidated Financial Statements subsidiaries or, in the Utility, except as for further discussion of the Credit Agreement.

specifically permitted by the terms of the loans or as required by applicable law or the In connection with the Utility's proposed plan of conditions adopted by the CPUC with respect to reorganization, PG&E Corporation intends to holding companies. However, the Credit negotiate with the lenders to obtain their consent Agreement generally permits: to the issuance of up to $700 million of PG&E Corporation equity and the contribution of some

• PG&E NEG LLC, PG&E NEG, and their of the proceeds of issuance to the capital of the respective subsidiaries to enter into sales Utility.

and other dispositions of assets in the ordinary course of business and in certain In connection with the Credit Agreement, PG&E qualified transactions; Corporation also has issued to the lenders

• PG&E Corporation to use existing cash to additional warrants to purchase 2,669,390 shares make investments in PG&E NEG (limited of common stock of PG&E Corporation, with an 24

exercise price of $0.01 per share. PG&E equal to the principal amount plus accrued and Corporation has agreed to provide, following unpaid interest (including any liquidated consummation of a plan of reorganization of the damages and pass-through dividends).

Utility, registration rights in connection with the shares issuable upon exercise of these warrants. CASH FLOWS The net proceeds of the Loans will be used to Utility fund corporate working capital and for general corporate purposes. The following section discusses the Utility's significant cash flows from operating, investing, PG&E Corporation's Convertible Subordinated and financing activities for the years ended Notes (Notes) in the aggregate principal amount December 31, 2002, 2001, and 2000.

of $280 million were issued on June 25, 2002.

Operating Activities The Notes, maturing on June 30, 2010, have an interest rate of 9.50 percent, and provide the Results from the Utility's consolidated cash flows holder of the Notes with a one-time right to from operating activities for the years ended require PG&E Corporation to repurchase the 2002, 2001, and 2000 are as follows:

Notes on June 30, 2007, at a purchase price (in maxions) Year Ended December 31, 2002 2001 2000 Net income (loss) ....................................... $1,819 $1,015 $(3,483)

Depreciation, amortization, and decommissioning included in net income ............................................. 1,193 896 3,511 Reversal of ISO accrual included in net income .................. (970)

Increase in accounts payable ............................... 198 1,312 3,063 Payments authorized by the Bankruptcy Court on amounts classified as liabilities subject to compromise ........................... (1,442) (16)

(Increase) Decrease in income taxes receivable ..... ............. (50) 1,120 (1,120)

Other operating activity adjustments .......................... 386 438 (1,416)

Net cash provided by operating activities .................... $1,134 $4,765 $555 Operating activities provided net cash of

• The Utility received a $1.1 billion income

$1.1 billion in 2002 and $4.8 billion in 2001. The tax refund in 2001; no comparable refund decrease during the period is primarily due to was received in 2002; the following factors:

• In 2002, approximately $901 million in The Utility filed for bankruptcy in principal owed to QFs prior to the April 2001, which automatically stayed all bankruptcy was repaid by the Utility payments on liabilities incurred prior to under Bankruptcy Court approved the bankruptcy. Subsequent to the agreements. Among other things, the bankruptcy, the Utility resumed paying its agreements provided for repayments of ongoing expenses in the ordinary course amounts owed to QFs prior to the of business. As a result, the growth in bankruptcy either in full or in 6 to 12 accounts payable is $1.1 billion lower in monthly installments; and 2002 compared to 2001; 25

• In 2002, the Bankruptcy Court issued an financial debt previously classified as order authorizing the Utility to pay pre- liabilities subject to compromise totaling and post-petition interest to: $433 million.

1. Holders of certain undisputed Operating activities provided net cash of claims, including commercial

$4.8 billion in 2001 and $0.6 billion in 2000. The paper, senior notes, floating rate increase in 2001 was primarily due to an notes, medium-term notes, increase in net income and the receipt of a Deferrable Interest Subordinated

$1.1 billion income tax refund in 2001. Of the

- Debentures (QUIDS), prior bond

$4.5 billion increase in net income, $2.6 billion claims, revolving line of credit was attributable to a decrease in depreciation, a claims, and secured debt claims; non-cash expense. See the Results of Operations

2. Trade creditors, including QFs; and section of this MD&A for a discussion of the Utility's net income.

3. Certain other general unsecured creditors.

Investing Activities The Utility paid approximately $1 billion in pre- and post-petition interest related to Results from the Utility's consolidated cash flows these claims during 2002. The interest from investing activities for the years ended payments included accrued interest on 2002, 2001, and 2000 are as follows:

(in millions) Year Ended December 31, 2002 2001 2000 Capital expenditures .......... ........................... $(1,546) $(1,343) $(1,245)

Other investing activities ........ .......................... 37 5 38 Net cash used by Investing activities ....................... $(1,509) $(1 ,338) $(1,207)

Cash used by investing activities in 2002, 2001, Financing Activities and 2000, was primarily for capital expenditures related to improvements to the Utility's electricity Results from the Utility's consolidated cash flows and natural gas transmission and distribution from financing activities for the years ended systems. 2002, 2001, and 2000 are as follows:

While the Utility is in bankruptcy, capital expenditures are being funded with cash provided by operating activities.

(In millions) Year Ended December 31, 2002 2001 2000 Net (repayments) borrowings under credit facilities and short-term borrowings ............................................. $ (28) $2,630 Net, long-term debt issued, matured, redeemed, or repurchased ......... (3-53) (111) 373 Rate reduction bonds matured ................................. (2590) (290) (290)

Common stock repurchased .................................. (275)

Dividends paid ............................................ (475)

Other financing activities ..................................... - (1) (26)

Net cash provided (used) by financing activities ................. $(6,23) $(430) $1,937 26

Except as contemplated in the Utility's proposed debt and rate reduction bonds. The repayment of plan of reorganization discussed in Note 2 of the long-term debt included payments on:

Notes to the Consolidated Financial Statements, the Utility has no plans to seek external (in mlcons) financing as a source of funding. Additionally, Medium-term notes ................ $ 18 the Utility is not allowed to pay dividends on its Mortgage bonds .................. 93 preferred or common stock while in bankruptcy Net repayment of long-term debt ...... $111 without Bankruptcy Court approval. As discussed in Note 9 and 10 of the Notes to the Consolidated Financial Statements, the Utility did The payments on the medium-term notes and not declare or pay common and preferred stock the mortgage bonds were made before the dividends in 2001 or 2002. Preferred stock Utility's April 2001 bankruptcy filing.

dividends have a cumulative feature in which preferred stock dividends must be brought PG&E Funding LLC repaid $290 million in current before any dividends can be distributed principal on its rate reduction bonds during to common stockholders. Further, the preferred 2001. As previously mentioned, the rate stocks have a mandatory sinking fund feature in reduction bonds are not included in the Utility's which funds are set-aside for the future periodic bankruptcy.

retirement of outstanding preferred stock. Until cumulative dividend payments on the Utility's 2000 preferred stock and mandatory sinking fund payments are made, the Utility may not pay Financing activities provided $1.9 billion of net dividends on its common stock. See Note 10 of cash in 2000 primarily due to borrowings under the Notes to the Consolidated Financial credit facilities and short-term borrowings, Statements for a discussion of the Utility's partially offset by (1) principal payments on preferred stock. long-term debt and rate reduction bonds, (2) common stock repurchases, and (3) dividend 2002 payments. Net borrowings under credit facilities and short-term borrowings included the Financing activities used $623 million of net cash following:

in 2002 primarily reflecting the repayments of long-term debt and rate reduction bonds. (in ciflions)

Pursuant to Bankruptcy Court approval, the Credit facility draws ...... ......... $ 614 Utility repaid $333 million in principal on its Commercial paper issuance .... ..... 776 mortgage bonds that matured in March 2002. 364-day floating rate notes issuance 1,240 PG&E Funding LLC, a wholly owned subsidiary Net borrowings under credit facilities of the Utility, also repaid $290 million in and short-term borrowings .... .... $2,630 principal on its rate reduction bonds during 2002. PG&E Funding LLC and the rate reduction bonds are not included in the Utility's bankruptcy.

2001 Financing activities used $430 million of net cash in 2001 primarily for repayments of long-term 27

The Utility issued, repaid, redeemed, or as well as dividends from PG&E NEG's repurchased long-term debt as follows: independent power producer generation project companies which are accounted for under the (in milons) equity method of accounting. If the commitments Issuance of: are not restructured, PG&E NEG and its Senior notes ....... ............. $680 subsidiaries will not generate sufficient funds to Maturity of: meet its outstanding cash requirements and may Mortgage bonds ...... ........... (110 ) file or be forced into bankruptcy.

Various medium-term notes .... ..... (113 )

Other long-term debt ..... ........ (3) In addition to the impacts of PG&E NEG's Repurchase of: downgrades, PG&E NEG's and its subsidiaries' Various pollution control loan ability to service these obligations is impacted by agreements ................... (81 ) constraints on the ability to move cash from one Net issuance, repayment, redemption, and subsidiary to another or to PG&E NEG itself.

repurchase of long-term debt ....... $373 PG&E NEG's subsidiaries must now independently determine, in light of each company's financial situation, whether any PG&E Funding LLC repaid $290 million in proposed dividend, distribution or intercompany principal on its rate reduction bonds during loan is permitted and is in such subsidiary's 2000. interest. Therefore, Consolidated Statements of Cash Flow and Consolidated Balance Sheets As previously mentioned, the rate reduction quantifying PG&E NEG's cash and cash bonds are not included in the Utility's equivalents do not reflect the cash actually bankruptcy. available to PG&E NEG or any particular subsidiary to meet its obligations.

In April 2000, a subsidiary of the Utility repurchased 11.9 million shares of the Utility's At January 31, 2003, PG&E NEG and its common stock from PG&E Corporation at a cost subsidiaries had the following unrestricted cash of $275 million. The repurchase was made so and short-term investment balances (not that the Utility could maintain its including in-transit items):

CPUC-authorized capital structure, which is the level of common and preferred equity the Utility (in milons) may maintain in relation to debt. PG&E NEG ......... ............. $126 PG&E ET and Subsidiaries ..... ...... 98 PG&E NEG PG&E Gen and Subsidiaries .... ...... 97 PG&E GTN and Subsidiaries .... ...... 17 The cash from operations for the years 2002, Other .......................... 60 2001, and 2000 will not be indicative of the Consolidated PG&E NEG ..... ....... $398 future cash flow from operations due to the changes in the operations of PG&E NEG (discussed above). Operating Activities To the extent that the commitments of PG&E Results from PG&E NEG's consolidated cash NEG and its subsidiaries can be restructured, flows from operating activities for the years future cash from operations will be principally ended 2002, 2001, and 2000 are as follows on a generated by the PG&E NEG pipeline business summarized basis:

28

(in nmlons) 2002 2001 2000 Net income (loss) .$(3,423) $171 $152 Adjustments to reconcile net income to net cash (used) provided by operating activities before price risk management assets and liabilities .3,539 (38) 119 Subtotal ................................................ 116 133 271 Price risk management assets and liabilities, net ..................... 99 130 (21)

Net effect of changes in operating assets and liabilities:

Restricted cash ............................................. (62) (62) 3 Net, accounts receivable, accounts payable and accrued liabilities ......... 100 42 65 Inventories, prepaids, deposits and other .......................... (471) 143 (154)

Net cash provided (used) by operating activities ................... $ (218) $386 $164 During 2002, PG&E NEG used net cash from $143 million primarily due to repayments of operating activities of $218 million. Net cash margin deposits in PG&E NEG's trading from operating activities before changes in operations. Offsetting these cash inflows were operating assets and liabilities and price risk $62 million of increased restricted cash management assets and liabilities was requirements in several of PG&E NEG's projects

$116 million in 2002, created principally from in construction.

results of operations offset by the timing of deferred tax benefits and lower distributions During 2000, PG&E NEG generated net cash from unconsolidated affiliates. Change in price from operating activities of $164 million. Net risk management assets and liabilities increased cash from operating activities before changes in cash flow by $99 million due to realization of operating assets and liabilities and price risk cash from price risk management activities. The management assets and liabilities was change in inventories, prepaid expenses, $271 million in 2000, created principally from the deposits, and other liabilities decreased cash timing of deferred tax benefits and higher flow by $471 million primarily due to increased distributions from unconsolidated affiliates.

credit collateral deposit requirements in PG&E NEG's trading operations. Adding to these cash Change in price risk management assets and outflows were $62 million of increased in liabilities decreased cash flow by $21 million.

restricted cash requirements. PG&E NEG's net cash inflow related to the change in accounts receivables, accounts During 2001, PG&E NEG generated net cash payable, and accrued liabilities increased cash from operating activities of $386 million. Net flow by $65 million. The change in inventories, cash fr6m operating activities before changes in prepaid expenses, deposits, and other liabilities operating assets and liabilities and price risk decreased cash flow by $154 million principally management assets and liabilities was due to increased margin deposits in PG&E NEG's

$133 million in 2001, created principally from trading operations.

results of operations offset by the timing of deferred tax benefits and lower distributions Investing Activities from unconsolidated affiliates. Change in price risk management assets and liabilities increased The cash outflows from investing activities for cash flow by $130 million due to realization of the years 2002, 2001, and 2000 will not be cash from price risk management activities. indicative of the future cash outflow from PG&E NEG's net cash inflow related to the investing activities due to the changes in the change in accounts receivable, accounts payable, operations of PG&E NEG (discussed above).

and accrued liabilities from operations assets and Depending on the results of the restructuring liabilities was $42 million. The change in negotiations discussed above, it is anticipated inventories, prepaid expenses, deposits, and that future cash outflows from investing other liabilities increased cash flow by operations will be principally generated by our 29

pipeline business principally related to Results from PG&E NEG's consolidated cash maintenance capital expenditures. flows from investing activities for the years ended 2002, 2001, and 2000 are as follows:

(in millons) 2002 2001 2000 Capital expenditures ......... ............................... $(1,485) $(1,426) $(900)

Acquisition of generating assets ................................ - (107) (311)

Proceeds from sale of assets (equity investments) ..... .............. 46 - 442 Proceeds from sale leaseback .................................. 340 - -

Long-term prepayment on turbines .............................. (15) (89) (132)

Investment in Southaven project ................................ (74) - -

Repayment of note receivable from PG&E Corporation .... ............ 75 - -

Long-term receivable ........................................ 136 81 75 Other, net ............. .................................. (63) 7 (38)

Net cash used in Investing activities .......................... $(1,040) $(1,534) $(864)

Total capital expenditures detailed by business segment and expenditure amount associated with construction work in progress for the year ended 2002, 2001, and 2000 are as follows:

(in mlions) 2002 2001 2000 Capital expenditure by business segment:

Integrated energy and marketing activities ......................... $1,294 $1,324 $885 Interstate pipeline operations .................................. 191 102 15 Total capital expenditures .................................... $1,485 $1,426 $900 Expenditure associated with construction work in progress .............. $1,353 $1,318 $722 During 2002, PG&E NEG used net cash of assets and related turbine and other equipments

$1,040 million in investing activities compared to contracts will be abandoned and terminated

$1,534 million for the same period in 2001, or a during 2003. As a result of investment decrease of $494 million. The decrease in cash downgrades, PG&E ET replaced a $74 million used in investing activities from period to period letter of credit issued to Southaven with cash was primarily due to proceeds from the Attala pursuant to a subordinated loan agreement. No Generating sale leaseback transaction providing such activity occurred in 2001.

$340 million, proceeds of $46 million from the partial sale of PG&E NEG's interest in Hermiston Included in investing activities for 2002 and 2001 and the repayment of a $75 million loan from are cash flows of $136 million and $81 million PG&E Corporation to PG&E GTN. Offsetting respectively related to the long-term receivable these proceeds were capital expenditures of from New England Power Company (NEPC)

$1,485 million in 2002 versus $1,426 million in associated with the assumption of power 2001. These capital expenditures were used purchase agreements. These cash flows offset primarily for construction work in progress and cash payments made to NEPC which are were financed by non-recourse debt. Due to reflected in operating activities. PG&E NEG PG&E NEG's default on making equity intends to sell USGenNE in 2003.

commitments, these construction projects will potentially be transferred to lenders in 2003. During 2001, PG&E NEG used net cash of Advanced development and turbine prepayments $1.5 billion for investing activities, which were were $144 million less in 2002 versus 2001 due primarily attributable to capital expenditures to the reductions and cancellations of new associated with generating projects in construction efforts. All remaining development construction, its purchase of the Mountain View 30

wind project, and prepayments on turbines and $75 million related to the long-term receivable related equipment. from NEPC associated with the assumption of power purchase agreements. These cash flows During 2000, PG&E NEG used net cash of offset cash payments made to NEPC which are

$864 million for investing activities. The primary reflected in operating activities.

cash outflows from investing activities were for capital expenditures associated with generating Financing Activities projects in construction, the acquisition of Attala, and prepayments on the turbines and related Results from PG&E NEG's consolidated cash equipment. These outflows were partially offset flows from financing activities for the years by the receipt of $442 million in proceeds from ended December 31, 2002, 2001, and 2000 are as sales of assets and equity investments. Included follows:

in investing activities is a cash flow of (in miions) 2002 2001 2000 Net borrowings (repayments) under credit facilities .................... $ - $ (189) $ (5)

Repayment of obligations due related parties and affiliates .... .......... (100) -

Advances from PG&E Corporation ................................ - - 79 Long-term debt issued ......... ............................... 1,506 1,114 711 Long-term debt matured, redeemed, or repurchased ..... .............. (403) (757) (85)

Notes issuance, net of discount and issuance costs ..... ............... - 987 -

Deferred financing costs ......... .............................. (41) (39) -

Capital contributions .......... ............................... - - 608 Distributions ............................................... - - (106)

Net cash provided by Enancing activities ........................ $ 962 $1,116 $1,202 During 2002, PG&E NEG provided net cash capital contributions by PG&E Corporation of flows from financing activities of $962 million. $608 million, partially offset by distributions to PG&E Corporation of $106 million.

PG&E NEG's cash inflows from financing activities were primarily attributable to increases PG&E Corporation in long-term debt issued relating to the continuing completion of PG&E NEG's The following section discusses PG&E construction facilities and borrowings under Corporation's significant cash flows from construction financing. operating, investing, and financing activities for the years ended December 31, 2002, 2001, and During 2001, net cash provided by financing 2000.

activities was $1.1 billion, principally from the net proceeds related to the issuance of the Operating Activities Senior Unsecured Notes due 2011.

Results from PG&E Corporation's consolidated During 2000, net cash provided by financing cash flows from operating activities for the years activities was $1.2 billion. Net cash provided by ended December 31, 2002, 2001, and 2000 are as financing activities resulted primarily from follows:

non-recourse project debt of $711 million, and 31

(i,. mi11ons) Year Ellded December 31, (in millions) Year Ended December 31, 2002 2001 2000 Net income (loss) ........................................ $ (874) $1,099 $(3,364)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, amortization, and decommissioning ................ 1,309 1,002 3,595 Net effect of changes in operating assets and liabilities:

Restricted cash ....................................... (513) (66) (6)

Accounts receivable ................................... 51 1,000 (1,941)

Accounts payable ..................................... 377 1,213 4,200 Payments authorized by the Bankruptcy Court on amounts classified as liabilities subject to compromise ....................... (1,442) (16)

Assets and liabilities of operations held for sale ................ 34 (117) 64 Other, net ............................................ 1,592 1,166 (1,793)

Net cash provided by operating activities .... $ 534 $5,281 $ 755 Net cash provided by operating activities was credit collateral deposit requirements in

$534 million in 2002, $5,281 million in 2001, and PG&E NEG's trading operations.

$755 million in 2000.

The increase during 2001 was primarily due to The decrease during 2002 was primarily due to the Utility's pre-petition obligations being stayed the following factors: under the Bankruptcy Code, and deliveries on previously held trading positions at PG&E NEG.

- The continued operation of the Utility as a debtor-in-possession under the Investing Activities Bankruptcy Code and the prior year impact of an income tax refund.

Results from PG&E Corporation's consolidated

• Increased working capital requirements of cash flows from investing activities for the year PG&E NEG, primarily due to increased ended 2002, 2001, and 2000 are as follows:

(in milons) Year Ended December 31, 2002 2001 2000 Capital expenditures ..................... .... ............. $(3,032) $(2,773) $(2,334)

Other, net ............................ ..........I............. 482 (103) 656 Net cash used by investing activities ....... .................. ......

$(2,550) $(2,876) $(1,678)

Net cash used in investing activities in 2002, The decrease in cash used in investing activities 2001, and 2000 was primarily for capital in 2002, compared to 2001, was primarily due to expenditures at the Utility and construction and the proceeds received by PG&E NEG from Attala development projects at PG&E NEG. Generating.

32

Financing Activities Results from PG&E Corporation's consolidated cash flows from financing activities for the year ended 2002, 2001, and 2000 are as follows:

(in mllons) Year Ended December 31, 2002 2001 2000 Net borrowings (repayments) under credit facilities . ............... $ - $(1,148) $ 2,846 Long-term debt issued ..................... .............. . 2,414

... 3,008 1,659 Long-term debt matured, redeemed, or repurchased .............. ....(1,644) (868) (1,155)

Dividends paid........................... .............. .. (109)

....- (436)

Other, net .............................. .............. . ... (214) (316) 86 Net cash provided by financing activities ..... .............. $ 556 $ 567 $ 3,000 Net cash generated through financing activities in PG&E NEG's increased borrowings under new 2002, 2001, and 2000 was principally achieved and existing credit facilities.

through long-term debt issuances and increased borrowings under new and existing credit During 2002, PG&E Corporation negotiated new facilities. The decrease in net cash provided by terms to amend the Original Credit Agreement, financing activities in 2002, compared to 2001, of reducing the principal balance from $1 billion to

$11 million, was a result of the Utility's $720 million which included $300 million in new repayment of long-term debt, partly offset by long-term debt.

33

RESULTS OF OPERATONS In this section, PG&E Corporation discusses earnings and the factors affecting them for each operating segment. The table below details certain items from the accompanying Consolidated Statements of Operations by operating segment for the years ended December 31, 2002, 2001, and 2000.

PG&E National Energy Group Integrated Energy & interstate PG&E Corporation, Total Marketing Pipeline PG&E NEG El;imnation$ and (n millions) Utility PG&E NEG Activities Operations Eliminatinn I Other () Total 2002 Operating revenues " .... S10,514

$......... $ 2,075 $ 1,855 $ 253 $03) $ (94) $12,495 Operating expenses ... .......... 6,601 4,812 4,653 109 50 (50) 11,363 Operating income (loss) ... ........ $ 3.913 $(2,737) S(2,798) $ 144 $(83) $ (44) 1,132 Interest income ................ 132 Interest expense ............... (1,454)

Other income (expense), net ........ 90 Loss before income taxes .......... (100)

Income benefit ................ (43)

Loss from continuing operationS...... (57)

Net loss .................... $ (874) 2001 u)

Operating revenues ............ 510,462

$2, $ 1,920 $ 1,680 S 246 $ (6) S(172) $12,210 Operating expenses .......... ... 7.984 1,787 1,679 109 (1) (152) 9,619 Operating income (loss) ........... S 2,478 $ 133 $ I $ 137 $ (5) $ (20) 2,591 Interest income . 167 Interest expense (1,209)

Other income (expense), net . (31)

Income before income taxes. 1,518 Income taxes . 535 Income from continuing operations. 983 Net income . $ 1,099 2000 (3)

Operating revenues 12 .... S$........

9,637 $3,127 $ 2,009 $1,112 $ 6 5(196) $12,568 Operating expenses ... .......... 14,838 2,858 1,937 906 15 (199) 17,497 Operating income (lo&ss) .......... . $(5,201) S 269 $ 72 $ 206 $ (9) $ 3 (4,929)

Interest income ................ 214 Interest expense ............... (788)

Other income (expense), net ........ (23)

Loss before income taxes .......... (5,526)

Income benefit ................ (2,103)

Loss from continuing operations ...... (3,423)

Net loss .... ................ S(5,364)

'" PG&E Corporation eliminates all inter-segment transactions in consolidation.

tD Operating revenues and expenses reflect the adoption during 2002 of a new accounting policy implementing a change from gross to net method of reporting revenues and expenses on trading activities. Prior year amounts for trading activities have been reclassified to conform with the new net presentation.

'5 Prior periods amounts have been restated to reflect the reclassification of USGenNE, Mountain View, and LT'Canada operating results to discontinued operations.

34

PG&E Corporation - Consolidated period in 2001, and a, net loss of $3,364 million for the same period in 2000.

Overall Results The significant changes in pre-tax income for PG&E Corporation's net loss for the year ended both years ended December 31, 2002 and 2001, December 31, 2002, was $874 million, compared when compared to prior year are summarized in to net income of $1,099 million for the same the table below:

(in mSlons) 2002 2001 PG&E Corporation Interest expense .......... ................................... (163) (87)

Other income ........... .................................... 79 (1)

Utility Electric revenues ............................................. 852 472 Natural gas revenues .......................................... (800) 353 Cost of electricity .......... ................................... 1,292 3,967 Deferred electric procurement costs ................................ - (6,465)

Cost of natural gas ............................................ 878 (407)

Operating and maintenance ..................................... (432) 302 Depreciation amortization and decommissioning ....................... (297) 2,615 Provision for loss on generation-related regulatory assets and under-collected power costs ........... .................................... - 6,939 Reorganization fees and expenses ................................. (58) (97)

Interest and other income ....................................... (49) (431)

Interest expense ............................................. (582) (2,750)

PG&E NEG Revenues ...... .155 ....................... (1,207)

Cost of revenues ........... .................................. (197) 1,217 Impairments, write-offs, and other charges ........................... (2,767) -

Operating expenses .......... ................................. (61) (146)

Cumulative effect of change in accounting principle .................... (70) 9 Discontinued operations ........ ................................ (1,244) 48 35

PG&E Corporation's results of operations Utility continue to be impacted by the California energy crisis, the Utility's bankruptcy filing, and the Electric Revenues current liquidity and financial downturn at PG&E NEG. The overall results of the Utility and PG&E The following table shows a breakdown of the NEG are discussed separately below. Please see Utility's electric revenue by customer class:

the Liquidity and Financial Resources section above, and Notes 2 and 3 of the Notes to the (in minions) Year ended December 31, Consolidated Financial Statements for more 2002 2001 2000 information. Residential ......... $ 3,646 $ 3,396 $ 3,062 Commercial ........ 4,588 4,105 3,110 The changes in performance for the years ended Industrial .......... 1,449 1,554 1,053 Agricultural ........ 520 525 420 December 31, 2002 and 2001, are attributable to the following factors: Total ........... 10,203 9,580 7,645 Direct access credits . . $ (285) $ (461) $(1,055)

DWR pass-through PG&E Corporation revenue ......... (2,056) (2,173) -

Miscellaneous ....... 316 380 264 Interest Expense Total electric operating revenues $ 8,178 $ 7,326 $ 6,854 In the third quarter, PG&E Corporation wrote off unamortized loan fees and discounts of

$83 million relating to the prepayments of a Electric revenues in 2002 increased $852 million, portion of outstanding debt and $70 million or 11.6 percent, from 2001. This increase in relating to ratings waiver extensions. In addition, electric revenues was primarily due to three PG&E Corporation wrote off $38 million of factors:

unamortized loan discounts representing the

• The amount of CPUC-authorized value of unvested PG&E NEG options associated surcharges increased $751 million in 2002 with the note prepayment. from 2001. This increase reflects the collection of a $0.035 per kilowatt-hour Other Income (kWh) surcharge, effective June 2001, for all of 2002, as compared to the collection The third quarter change in the market value of of this surcharge for only seven months vested PG&E NEG warrants previously issued in during the twelve-month period ended connection with the PG&E Corporation March 1, December 31, 2001.

2001, Credit Agreement totaled $71 million.

. Direct access credits in 2002 decreased Diviidends $176 million from 2001. In accordance with CPUC regulations, the Utility No dividends were declared in 2002 or 2001 in provides an energy credit to direct access accordance with the Credit Agreement, which customers (those who buy their electricity prohibits PG&E Corporation from declaring or from another energy service provider, or paying dividends until the term loans have been ESP). The Utility bills direct access repaid. customers based on fully bundled rates, which includes generation, distribution, In March 2001, PG&E Corporation paid transmission, and other components.

$109 million of defaulted fourth quarter 2000 However, each direct access customer dividends in conjunction with the refinancing of receives an energy credit equal to the PG&E Corporation obligations. procurement component of the fully bundled rates, which includes (1) the Utility's estimated procurement and generation cost, and (2) the Utility's 36

generation component of the frozen rate access customers, and (2) an increase in for electricity provided by the DWR. the amount of electricity the Utility was able to purchase from QFs due to The decrease in direct access credits was renegotiated payment terms through the due to a decrease in the average direct Utility's bankruptcy proceeding. The access credit per kWh offset by an decrease in the Utility's net open position increase in the total electricity provided to in 2002 was partially offset by the accrual direct access customers by ESPs. The of an additional $369 million in average direct access credit per kWh was pass-through revenues in 2002 due to higher in 2001 because in the beginning changes proposed by the DWR to the of 2001 the Utility used the California methodology used to calculate DWR Power Exchange (PX) price for wholesale remittances (see Note 2 of the Notes to electricity to calculate direct access credits. the Consolidated Financial Statements).

Subsequent to the closure of the PX in January 2001, direct access credits have Electric revenues in 2001 increased $472 million, been calculated based on the or 6.9 percent, from 2000 mainly due to the procurement component of the fully CPUC-authorized surcharges implemented in bundled rate, which has been significantly January and June 2001 and a decrease in direct lower than the PX price. The average access credits. The decrease in direct access direct access credit decreased from $0.116 credits was due to a decrease in total electricity per kWh in 2001 to $0.038 per kWh in provided to direct access customers by direct 2002. In 2002, ESPs supplied access ESPs. In 2001, energy service providers approximately 7,433 gigawatt-hours supplied approximately 3,982 GWh of electricity (GWh) of electricity to direct access to direct access customers, compared to 9,662 customers, compared to 3,982 GWh in GWh in 2000.

2001.

The increase in electric revenues in 2001 was Revenue passed through to the DWR offset by revenues of $2,173 million passed decreased by $117 million in 2002. The through to the DWR in 2001, with no such Utility passes revenue through to the amount in 2000.

DWR for electricity procured by the DWR to cover the Utility's net open position Cost of Electricity (the amount of electricity needed by retail electric customers that cannot be met by The following table shows a breakdown of the utility-owned generation or electricity Utility's cost of electricity:

under contract to the Utility). Since January 2001, the DWR has been (in milons) Year ended December 31, responsible for procuring electricity 2002 2001 2000 required to cover the Utility's net open Cost of purchased position. Revenues collected on behalf of power .......... $ 1,980 $ 3,224 $ 6,642 the DWR and the related costs are not Fuel used in own included in the Utility's Consolidated generation ....... 97 102 99 Statement of Operations because the Other adjustments to Utility acts only as the DWR's billing and cost of electricity ... (595) (552) collection agent. Total cost of electricity $ 1,482 $ 2,774 $ 6,741 Average cost of The decrease in DWR pass-through purchased power revenues in 2002 was primarily due to a per kWh ........ $ 0.081 $ 0.143 $ 0.152 decrease in the Utility's net open position, Total purchased power which was created by (1) an increase in (GWh) ......... 24,552 22,592 43,762 electricity supplied by ESPs to direct 37

The cost of electricity in 2002 decreased decrease was primarily due to the following two

$1,292 million, or 46.6 percent, from 2001. The factors:

decrease was attributable to the following factors:

• After the first half of January 2001, the Utility no longer purchased electricity A decrease in the average cost of through the PX market. Instead, the DWR purchased power. The more favorable purchased electricity on behalf of the price reflected the significantly lower Utility's customers to cover the Utility's prices for electricity subsequent to the net open position; and stabilization of the energy market in the second half of 2001. In addition, the

• A statewide energy conservation campaign average cost of electricity decreased - led the Utility's customers to use approximately 3 percent less energy than because the Utility purchased more electricity from QFs, other generators, and in 2000.

irrigation districts, which provided electricity at a lower cost than the In 2000, the Utility deferred $6.5 billion in under-electricity the Utility purchased on the collected electric procurement costs. At the end market in the beginning of 2001. In 2002, of 2000, the Utility could no longer conclude that its under-collected electric procurement costs the DWR purchased all of the electricity needed to meet the Utility's net open and generation-related regulatory assets were position, whereas in 2001 the Utility probable of recovery and therefore charged purchased the electricity itself through the $6.9 billion to expense for these costs. There PX market through the first half of were no similar events in 2001.

January. As previously discussed, the Utility serves as a collection agent for the Natural Gas Revenues DWR and therefore does not reflect the Natural gas revenues are made up of bundled DWR's cost of electricity in its gas revenues and transportation only revenues.

Consolidated Statement of Operations; and The following table shows a breakdown of the

• A net $595 million reduction to the cost of Utility's natural gas revenue:

electricity recorded in March 2002 as a result of FERC and CPUC decisions, which (in milTlons) Year ended December 31, allowed the Utility to reverse previously 2002 2001 2000 accrued California Independent System Bundled gas revenues . . . $1,882 $3,107 $2,229 Operator (ISO) charges and to true-up the Transportation service amount of previously accrued only revenue........ 316 375 338 Other .............. 138 (346) 216 pass-through revenues payable to the DWR (see Note 2 of the Notes to the Total Natural Gas Revenues .......... $2,336 $3,136 $2,783 Consolidated Financial Statements).

Offsetting the above impacts were amounts In 2002, natural gas revenues decreased recorded during 2001 that reduced purchased $800 million, or 25.5 percent, from 2001 power costs by $552 million for the market value primarily as a result of a lower average cost of of terminated bilateral contracts with no similar natural gas, which was passed along to amounts in 2002. customers through lower rates. The average bundled price of natural gas sold during 2002 The cost of electricity in 2001 decreased was $6.72 per thousand cubic feet (Mcf) as

$3,967 million, or 58.8 percent, from 2000. This compared to $10.55 per Mcf in 2001.

The decrease in transportation service only revenue resulted primarily from a decrease in 38

demand for gas transportation services by In 2002, the Utility's cost of natural gas gas-fired electric generators in California. decreased $878 million, or 47.9 percent, from 2001 primarily due to a decrease in the average Increases in other gas revenues were mainly due market price of natural gas purchased from $6.77 to a decrease in the deferral of natural gas per Mcf in 2001 to $3.38 per Mcf in 2002.

revenue in 2002, which was attributed to the abnormally high price for natural gas in the Additionally, the Utility's cost to transport gas to beginning of 2001. The Utility tracks natural gas its service area decreased significantly in 2002 revenues and costs in natural gas balancing due to $111 million in costs recognized in 2001 accounts. Over-collections and under-collections related to the involuntary termination of gas are deferred until they are refunded to or transportation hedges caused by a decline in the received from the Utility's customers through rate Utility's credit rating. There were no similar adjustments. events in 2002.

In 2001, natural gas revenues increased In 2001, the Utility's cost of natural gas increased

$353 million, or 12.7 percent, due to a higher $407 million, or 28.6 percent, primarily due to an average cost of natural gas, which was passed increase in the average cost of natural gas from on to customers through higher rates. The $5.07 per Mcf in 2000 to $6.77 per Mcf in 2001.

average bundled price of natural gas sold during Furthermore, as mentioned above, in 2001 the 2001 was $10.55 per Mcf, compared to $8.40 per Utility's cost to transport gas to its service area Mcf in 2000. The increase was offset by an increased significantly due to $111 million in approximate 4 percent decrease in usage in 2001 costs related to the involuntary termination of primarily as a result of conservation efforts. gas transportation hedges.

The increase in transportation service only Other Operating Expenses revenue was primarily due to an increase in demand for gas transportation services by Operating and Maintenance gas-fired electric generators in California.

In 2002, the Utility's operating and maintenance Decreases in other gas revenues were mainly expenses increased $432 million, or 18.1 percent, due to an increase in the deferral of natural gas from 2001. This increase is mainly due to the revenue in 2001, which was attributed to the following factors:

abnormally high price for natural gas in 2001. As

• Increases in employee benefit plan-related previously discussed, over-collections are expenses primarily due to unfavorable deferred in natural gas balancing accounts until returns on plan investments and lower they are refunded to customers through rate interest rates, which caused a decrease in adjustments. discount rates on the Utility's present-valued benefit obligations; Cost of Natural Gas

• Increases in environmental liability The following table shows a breakdown of the estimates; Utility's cost of natural gas:

• Increases in customer accounts and Year ended service expenses related to the Utility's (in Silons) December 31, new customer billing system; 2002 2001 2000

• The amortization of previously deferred Cost of natural gas electric transmission related costs, which purchased .. $853 $1,593 $1,331 Cost of gas transportation 101 239 94 are now being collected in rates; and Total cost of natural gas . $954 $1,832 $1,425

• The deferral of over-collected electric revenue associated with the rate reduction 39

bonds. Prior to 2000, these revenues were decrease was offset by increases in interest on used to finance the rate reduction short-term investments and balancing accounts.

implemented in 1998.

Interest Expense In 2001, the Utility's operating and maintenance expenses decreased $302 million, or In 2002, the Utility's interest expense increased 11.2 percent, primarily due to a reserve for $14 million, or 1.4 percent, from 2001 due to the chromium litigation of $140 million recorded in Utility's bankruptcy proceeding, which has 2000, and lower regulatory and generation- resulted in higher negotiated interest rates and related costs. an increased level of unpaid debts accruing interest. See the discussion of interest rates in Depreciation, Amortization, and Note 2 of the Notes to the Consolidated Financial Decommissioning Statements.

Depreciation, amortization, and decommissioning In 2001, the Utility's interest expense increased expenses increased $297 million, or 33.1 percent, $355 million, or 57.3 percent, compared to 2000 in 2002. This increase was due mainly to due to increased debt levels and higher interest amortization of the rate reduction bond rates as a result of the Utility's credit rating regulatory asset, which began in January 2002, downgrade and subsequent bankruptcy.

and totaled $290 million through December 31, 2002. The rate reduction bond regulatory asset is Reorganization Fees and Expenses discussed further in the "Regulatory Matters" section of this MD&A. In accordance with SOP 90-7, the Utility reports reorganization fees and expenses separately on Depreciation, amortization, and decommissioning the Consolidated Statements of Operations. Such expenses decreased $2,615 million, or costs primarily include professional fees for 74.5 percent, in 2001 due to accelerated services in connection with Chapter 11 depreciation of generation-related assets in 2000. proceedings and totaled $155 million in 2002 Less depreciation was recorded in 2001 as the and $97 million in 2001.

majority of the generation-related assets had been fully depreciated after the acceleration. PG&E NEG Interest Income Overall Results In accordance with the American Institute of The year ended 2002 included an expected loss Certified Public Accountants' Statement of on the disposal of USGenNE of $1.1 billion and Position (SOP) 90-7, the Utility reports on ET Canada of $25 million. Additionally, the reorganization interest income separately on the earnings from operations of USGenNE, ET Consolidated Statements of Operations. Such Canada, and Mountain View were reclassified to income primarily includes interest earned on discontinued operations. USGenNE, ET Canada, cash accumulated during the proceedings. and Mountain View Power Partners, LLC and Interest income decreased $49 million, or Mountain View Power Partners II, LLC 39.8 percent, in 2002. The decrease in interest (collectively referred to as Mountain View) were income in 2002 was due in most part to lower determined to be Assets Held for Sale per SPAS average interest rates on the Utility's short-term No. 144. As such, their operating results were investments. reclassified to discontinued operations and an evaluation of the value on an asset-by-asset basis In 2001, the Utility's interest income decreased conducted. PG&E NEG determined that

$63 million, or 33.9 percent, compared to 2000 USGenNE's and ET Canada's book values due primarily to the write-off of generation- exceeded their anticipated selling prices and as related regulatory balancing account interest. The such recorded losses on disposal. Earnings from 40

operations included in discontinued operations PG&-E NEG's income from continuing operations were $11 million or a decrease of $96 million (after-tax) was $55 million in 2001 or a decrease principally due to USGenNE's unfavorable of $38 million from the prior year. The decline in operating results and market conditions in New pre-tax operating income of $97 million in 2001 England. was primarily due to the sale of Pacific Gas Transmission Teco, Inc., and subsidiaries The year ended 2002 included a net loss for the (collectively referred to as PG&E GMT) in cumulative effect of a change in accounting December 2000 which provided operating principle of $61 million. The cumulative effect income of $77 million in 2000, and a charge in was based on PG&E NEG's adoption as of the fourth quarter of 2000 of $60 million related April 1, 2002, of interpretations issued by the to the termination of certain contracts resulting Derivatives Implementation Group (DIG), from the Enron bankruptcy (principally related to DIG C15 and DIG C16, reflecting the PG&E NEG's energy trading business). These mark-to-market value of certain contracts that declines were partially offset by the sale of a had previously been accounted for under the development project in the third quarter of 2001, accrual basis as normal purchases and sales. which provided operating income of $23 million, and general improvement in operating margins PG&E NEG's income from continuing operations in the Integrated Energy and Marketing Activities (after-tax) was a loss of $2.2 billion in 2002 or a (Energy) segment. Net interest expense was decrease of $2.3 billion from the prior year. The $33 million lower in 2001 as compared to the decline in pre-tax operating income was mainly prior year, principally due to increased due to one-time impairments, write-offs and capitalization of interest for projects under other charges previously discussed and taken construction.

during 2002 of $2.8 billion.

Operating Revenues PG&E NEG's net income (after discontinued operations and cumulative effect of a change in PG&E NEG's operating revenues were accounting principle) was $171 million for the $2.1 billion for the year ended 2002, an increase year ended 2001, an increase of $19 million from of $155 million from the year ended 2001. These the year ended 2000. revenue increases occurred primarily in PG&E NEG's Energy segment principally due to new The year ended 2001 included earnings from generation plants coming on line within the discontinued operations related to USGenNE, wholesale energy business. The principal drivers Mountain View, and ET Canada of $107 million, in the increase in PG&E NEG's Interstate Pipeline or an increase of $8 million from 2000. In Operation (Pipeline) segment's operating addition, the year ended 2000 included a loss revenues, which increased $7 million, were due from discontinued operations of $40 million to the North Baja pipeline commencing related to losses on the disposal of PG&E Energy operations and PG&E GTN contract termination Services Corporation. settlements. These operating revenue increases in the Pipeline segment were slightly offset by The year ended 2001 included a net gain for the weak pricing fundamentals on gas transportation cumulative effect of a change in accounting to the California and Pacific Northwest gas principle of $9 million. The cumulative effect markets compared to the same period last year.

was based on an interpretation issued by the DIG CHi that clarified how certain commodity PG&E NEG's operating revenues were contracts should be treated. In applying this new $1.9 billion in 2001, a decrease of $1.2 billion or DIG guidance, PG&E NEG determined that one 39 percent from 2000. This dedine in operating of its derivative contracts no longer qualified for revenues occurred within both PG&E NEG's normal purchases and sales treatment and must Energy and Pipeline segments. The decline in be marked-to-market through earnings. PG&E NEG's Energy segment of $329 million is mainly due to lower trade volumes and lower 41

realized prices in the third and fourth quarter of PG&E NEG's Pipeline segment of $792 million is 2001. These declines generally were due to primarily due to the sale of PG&E GTT in higher commodity prices in the wake of the December 2000.

California energy crisis in the second half of 2000 and the decline in economic activity in the INFLATION U.S. in the second half of 2001. The decline in PG&E NEG's Pipeline segment of $866 million is PG&E Corporation and the Utility prepare primarily due to the sale of PG&E GTT in financial statements in accordance with December 2000. accounting principles generally accepted in the United States of America. This means PG&E Operating Expenses Corporation and the Utility report operating results in terms of historical costs and do not PG&E NEG's operating expenses were evaluate the impact of inflation.

$4.8 billion for the year ended 2002, an increase of $3 billion from the same period in the prior Inflation affects construction costs, operating year. These increases occurred primarily in PG&E expenses, and interest charges. In addition, the NEG's Energy segment, principally due to Utility's electric revenues do not reflect the impairments, write-offs, and other charges impact of inflation due to the current electric rate previously discussed of $2.8 billion. The cost of freeze. However, PG&E Corporation and the commodity sales and fuel increased $197 million Utility do not expect current inflation levels to in line with the increases in operating revenues, have a material adverse impact on PG&E compressed spark spreads, and new generation Corporation's or the Utility's financial position or plants coming on line within the wholesale results of operations.

energy business. Operations, maintenance and management costs increased $33 million in 2002 REGUILATORY MATTERS as compared to the same period last year primarily due to new plants coming on line. In A significant portion of PG&E Corporation's addition, depreciation and amortization costs operations is regulated by federal and state increased $15 million in the period also mainly regulatory commissions. These commissions due to new plants coming on line. Administrative oversee service levels and, in certain cases, and general costs increased in 2002 as compared PG&E Corporation's revenues and pricing for its to the same period last year due to charges regulated services.

associated with PG&E NEG's cost reduction and restructuring programs. These increases were Utility slightly offset on a year-to-date basis by lower costs in the first half of 2002 associated with The Utility is the only subsidiary with significant lower employee related expense. regulatory proceedings or issues at this time.

These are discussed below. Regulatory PG&E NEG's operating expenses were proceedings associated with electric industry

$1.8 billion in 2001, a decrease of $1.1 billion restructuring are further discussed in Note 2 of from 2000. This decline in operating expenses the Notes to the Consolidated Financial occurred within both PG&E NEG's Energy and Statements.

Pipeline segments. The decline in PG&E NEG's Energy segment of $258 million is mainly due to DWR Revenue Requirement and Servicing lower trade volumes and lower realized prices Order achieved primarily in the third and fourth quarters of 2001. These declines generally were In January 2001, the DWR began purchasing due to higher commodity prices in the wake of electricity on behalf of the Utility's customers in the California energy crisis in the second half of accordance with a new state law, Assembly Bill 2000, and the decline in economic activity in the (AB) IX, that authorized the DWR to purchase U.S. in the second half of 2001. The decline in electricity for California utility customers to the 42

extent that it could not be supplied or purchased true-up previous amounts passed through to the by the utilities (the amount of electricity needed DWR as well as future payments. Under its to meet customers' demand that cannot be statutory authority, the DWR may request the provided by the IOUs, either through their own CPUC to order the utilities to implement such generation or by suppliers under contracts with amendments, and the CPUC has approved such -

the IOUs, is referred to as the net open amendments in the past without significant position). The DWR initially purchased electricity change. In December 2002, the CPUC approved on the spot market until it was able to enter into an operating order requiring the Utility to long-term contracts for the supply of electricity. perform the operational, dispatch, and Under AB 1X, the DWR was prohibited from administrative functions for the DWR's allocated entering into new agreements to purchase contracts beginning on January 1, 2003. (See electricity to meet the net open position of the "CPUC Operating Order" below.) The operating California IOUs after December 31, 2002. order, which applies prospectively, includes the DWR's proposed method of calculating the The DWR pays for its costs of purchasing amount of revenues that the Utility must electricity from a revenue requirement charged pass-through to the DWR. As a result, as of to Utility ratepayers (power charge) and December 31, 2002, the Utility has accrued an proceeds of the DWR's $11.3 billion bond additional $369 million (pre-tax) liability for.

financing completed in November 2002 (see pass-through revenues for electricity provided by "DWR Bond Charge" below). the DWR to the Utility's customers in 2002 and 2001. A separate proceeding will consider a In February 2002, the CPUC approved a decision revision or true-up for the revenue requirements that set the statewide DWR revenue requirement remitted to the DWR for 2002 and 2001 costs, for 2001 and 2002. In March 2002, the CPUC once final 2002 cost data is available. This true-reallocated the amounts contained in the up proceeding is scheduled for April 2003.

February 2002 decision among the customers of the three California IOUs. The March 2002 In December 2002, the CPUC issued a decision decision allocated $4.4 billion of a total statewide allocating approximately $2 billion of the DWR's power charge revenue requirement of 2003 power charge-related revenue requirement approximately $9.0 billion to the Utility's to the Utility's customers. This revenue customers. Of the $4.4 billion allocated to the requirement includes the costs associated with customers of the Utility, approximately the DWR contracts allocated to the Utility's

$1.8 billion related to 2002 power charges and customers by the CPUC in September 2002. The approximately $2.6 billion related to 2001 power DWR plans to submit a revised 2003 power charges. charge-related revenue requirement to the CPUC in late March 2003.

In May 2002, the CPUC approved a servicing order between the Utility and the DWR, which Before the DWR's 2003 statewide revenue sets forth the terms and conditions under which requirement filing with the CPUC in August 2002, the Utility provides the transmission and the Utility filed comments with the DWR alleging distribution of the DWR-purchased electricity; that major portions of the DWR's revenue addresses billing, collection and related services requirements were not "just and reasonable" as on behalf of the DWR; and addresses the DWR's required by AB 1X and that the DWR was not compensation to the Utility for providing these complying with the procedural requirements of services. In October 2002, the DWR filed a AB 1X in making its determination. On proposed amendment to the CPUC's May 2002 August 26, 2002, the Utility filed with the DWR a servicing order. The DWR's proposed motion for reconsideration of the DWR's amendment changes the calculation that determination that its revenue requirements were determines the amount of revenues that the "just and reasonable." The DWR denied the Utility must pass-through to the DWR. This Utility's motion on October 8, 2002. On proposed amendment would also be used to October 17, 2002, the Utility filed a lawsuit in a 43

California court asking the court to find that the Senate Bil 1976 DWR's revenue requirements had not been demonstrated to be "just and reasonable" and Under AB 1X, the DWR is prohibited from lawful, and that the DWR had violated the entering into new agreements to purchase procedural requirements of AB IX in making its electricity to meet the net open position of the determination. In part, the Utility based its California IOUs after December 31, 2002. In allegations on the State of California's petition September 2002, the Governor signed California pending before the FERC seeking to set aside SB 1976 into law. SB 1976 required that each many of the DWR contracts on the basis that California IOU submit, within 60 days after the they are not "just and reasonable." The Utility CPUC allocated existing DWR contracts for asked that the court order the DWR's revenue electricity procurement to the customers of each requirement determination be withdrawn as California IOU, an electricity procurement plan invalid, and that the DWR be precluded from to meet the residual net open position associated imposing its revenue requirements on the Utility with that utility's customer demand. SB 1976 and its customers until it has complied with the requires that each procurement plan include one law. No schedule has yet been set for or more of the following features:

consideration of the lawsuit.

• A competitive procurement process under Until the CPUC modifies the curent frozen rate a format authorized by the CPUC, with structure, changes to the DWR's 2003 revenue the costs of procurement obtained in requirement may affect the Utility's future compliance with the authorized bidding earnings. Because the Utility acts as a collection format being recoverable in rates; agent for the DWR, amounts collected on behalf

• A clear, achievable, and quantifiable of the DWR (related to its revenue requirement) incentive mechanism that establishes are excluded from the Utility's revenues. benchmarks for procurement and authorizes the IOUs to procure electricity DWR Bond Charge from the market subject to comparison with the CPUC-authorized benchmarks; or On October 24, 2002, the CPUC issued a decision that, in part, imposes bond charges to

• Upfront and achievable standards and criteria to determine the acceptability and recover the DWR's bond costs from most bundled customers starting November 15, 2002, eligibility for rate recovery of a proposed although the decision found that the Utility transaction and an expedited CPUC would not need to increase customer's overall pre-approval process for proposed rates to incorporate the bond charge. The DWR bilateral contracts to ensure compliance bond charge also will be imposed on all direct with the individual utility's procurement access customers, as described below. plan.

On December 30, 2002, the CPUC revised the SB 1976 provides that the CPUC may not approve the procurement plan if it finds the plan 2003 bond charge to $0.005 per kWh, effective January 6, 2003. The Utility expects to accrue contains features or mechanisms, which would bond-related charges of approximately impair restoration of the IOU's creditworthiness

$336 million during the 12 months ending or would lead to a deterioration of the IOU's November 14, 2003. creditworthiness. SB 1976 also indicates that procurement activities in compliance with an Until the CPUC implements bottoms-up billing approved procurement plan will not be subject (billing for specific rate components) for the to after-the-fact reasonableness review. The Utility, any bond charges will reduce the amount CPUC is permitted to establish a regulatory of revenue available to recover previously process to verify and ensure that each contract was administered in accordance with its terms written-off under-collected purchased power costs and transition costs.

44

and that contract disputes are resolved Allocation of DWR Electricity to Customers reasonably. of the IOUs A central feature of the SB 1976 regulatory Consistent with applicable law and CPUC orders, framework is its direction to the CPUC to create since 2001, the Utility and the other California new electric procurement balancing accounts to lOUs have acted as the billing and collection track and allow recovery of the differences agents for the DWR's sales of its electricity to between recorded revenues and costs incurred retail customers. In September 2002, the CPUC under an approved procurement plan. The CPUC issued a decision to allocate the electricity must review the revenues and costs associated provided under existing DWR contracts to the with the IOU's electric procurement plan at least customers of the IOUs. This decision required semi-annually and adjust rates or order refunds, the Utility, along with the other IOUs, to begin as appropriate, to properly amortize the performing all the day-to-day scheduling, balancing accounts. Until January 1, 2006, the dispatch, and administrative functions associated CPUC must establish the schedule for amortizing with the DWR contracts allocated to the IOUs' the over-collections or under-collections in the portfolios on January 1, 2003. The DWR retains electric procurement balancing accounts so that legal and financial responsibility for these the aggregate over-collections or under- contracts.

collections reflected in the accounts do not exceed 5 percent of the IOU's actual recorded Under AB lX, the CPUC has no review authority generation revenues for the prior calendar year, over the reasonableness of procurement costs in excluding revenues collected on behalf of the the DWR's contracts, although the Utility's DWR. Mandatory semi-annual review and administration of DWR contracts allocated to its adjustment of the balancing accounts will customers and its dispatch of the electricity continue until January 1, 2006, after which time associated with those contracts may be subject to the CPUC is required to conduct electric reasonableness reviews. Under a December 2002 procurement balancing account reviews and interim opinion, the CPUC established a adjust retail ratemaking amortization schedules maximum annual procurement disallowance for the balancing accounts as the CPUC deems equal to twice the Utility's annual administrative appropriate and in a manner consistent with the costs of managing procurement activities, requirements of SB 1976 for timely recovery of including the administration and dispatch of electric procurement costs. electricity associated with DWR allocated contracts. The Utility anticipates that its annual On January 1, 2003, the California IOUs resumed administrative cost of managing procurement the function of procuring electricity to meet that activities in 2003 will be approximately portion of their customers' needs that is not $18 million.

covered by the combination of the allocation of electricity from existing DWR contracts and the IOU's own electric resources and contracts.

45

The DWR has stated publicly that it intends to orders, the CPUC noted that if the IOUs and the transfer full legal title of, and responsibility for, DWR eventually reach mutual agreement, the the DWRI electricity contracts to the IOUs as CPUC would consider modifying its decision on soon as possible. However, SB 1976 does not an expedited basis to terminate the operating contemplate a transfer of tide of the DWR orders and approve the operating agreements, contracts to the IOUs. In addition, the operating assuming that the operating agreements adopted order issued by the CPUC in December 2002 a framework that was substantially similar to the implementing the Utility's operational and one imposed by the operating orders.

scheduling responsibility with respect to the DWR allocated contracts specifies that the DWR On December 20, 2002, the Utility and the DWR will retain legal and financial responsibility for executed an operating agreement following the contracts and that the December 2002 order several months of negotiation. The agreement does not result in an assignment of the DWR provides that it will not become effective unless allocated contracts to the Utility. However, there approved by the CPUC. The Utility has submitted can be no assurance that either the State of the agreement to the CPUC for approval and has California or the CPUC will not provide the DWR requested that the CPUC terminate the operating with authority to affect such a transfer of legal order and approve the operating agreement.

title in the future. The Utility has informed the CPUC, the DWR, and the State of California that Although the operating order and the operating the Utility would vigorously oppose any attempt agreement have fundamentally the same to transfer the DWR allocated contracts to the objectives, the operating agreement, among Utility without its consent. other things:

• Provides an adequate contractual basis for CPUC Operating Order establishing a limited agency relationship between the Utility and the DWR; In December 2002, the CPUC adopted an operating order requiring the Utility to perform

• Limits the Utility's contractual liability to the operational, dispatch, and administrative the DWR and other parties to $5 million functions for the DWR's allocated contracts per year plus 10 percent of damages in beginning on January 1, 2003. (Similar operating excess of $5 million with a limit of orders were also adopted for the other two $50 million over the term of the California lOUs.) The operating order sets forth agreement; and the terms and conditions under which the Utility

• Clarifies that the DWR does not intend to, will administer the DWR allocated contracts and nor is it the DWR's responsibility to, requires the Utility to dispatch all of the review the Utility's least-cost dispatch generating assets within its portfolio on a performance, other than to verify least-cost basis for the benefit of the Utility's compliance with the supplier contracts.

customers. The order specifies that the DWR will retain legal and financial responsibility for the On December 30, 2002, the Utility filed an DWR allocated contracts and that the order does application for rehearing of the operating order not result in an assignment of the allocated DWR decision with the CPUC. On January 1, 2003, contracts to the Utility. after having reserved all rights associated with challenges to the operating order, the Utility Operating Agreement commenced providing contract administration, scheduling and dispatch services to the DWR The CPUC had previously ordered the IOUs to under the CPUC's operating order.

work with the DWR to submit to the CPUC proposed operating agreements governing the Approval of Procurement Plan DWR allocated contracts. When the operating orders were issued, the DWR and the IOUs had In October 2002, the CPUC issued a decision not yet finalized their separate operating ordering the Utility to resume full procurement agreements. In its decision issuing the operating on January 1, 2003. In December 2002, the CPUC 46

issued an interim opinion adopting the revised In February 2003, the Utility filed its 2003 ERRA electricity procurement plan for 2003 that the forecast application requesting that the CPUC Utility submitted in 2002 and authorized the reset the Utility's 2003 ERRA revenue Utility to enter into contracts designed to hedge requirement to $1.4 billion and that the ERRA its residual net open position for the first quarter trigger threshold of $224 million be adopted. The of 2004. The CPUC found that the maximum CPUC will examine the Utility's forecast of costs annual procurement disallowance exposure that for 2003 and will finalize the Utility's starting each IOU should face for all of its procurement ERRA revenue requirement and ERRA trigger activities should be limited to twice the IOU's threshold when it reviews the Utility's ERRA annual administrative costs of managing application.

procurement activities, including its administration and dispatch of electricity The Utility intends to submit its long-term associated with DWR contracts allocated to its procurement plan, covering the next 20 years by customers. The Utility anticipates that its annual April 1, 2003, and the CPUC has stated that it administrative costs of managing procurement plans to issue a final decision on the Utility's activities in 2003 will be approximately long-term procurement plan in November 2003.

$18 million. While the Utility's procurement plan covered procurement activities only for the 2003 In April 2001, the California Public Utilities Code calendar year, the CPUC authorized the IOUs to was amended to require that the CPUC ensure extend their planning into the first quarter of that errors in estimates of demand elasticity or 2004. sales by the Utility do not result in material over-or under-collections of costs by the Utility. The Effective January 1, 2003, the Utility established Utility intends to address implementation of this the Energy Resource Recovery Account (ERRA) new law in connection with pending to record and recover electricity costs, excluding proceedings at the CPUC relating to recovery of the DWR's electricity contract costs, associated components of its costs of service.

with the Utility's authorized procurement plan.

Electricity costs recorded in the ERRA include, 2001 Annual Transition Cost Proceeding:

but are not limited to, fuel costs for retained Review of Reasonableness of Electricity generation, QF contracts, inter-utility contracts, Procurement ISO charges, irrigation district contracts, other power purchase agreements, bilateral contracts, On January 11, 2002, as directed by the CPUC, forward hedges, pre-payments, collateral the Utility filed a report with the CPUC detailing requirements associated with procurement the reasonableness of the Utility's electric (including disposition of surplus electricity), and procurement and generation scheduling and ancillary services. The Utility offsets these costs dispatch activities for the period July 1, 2000, by reliability-must-run revenues, the Utility's through June 30, 2001. In this proceeding, the allocation of surplus sales revenues and the CPUC will review the reasonableness of the ERRA revenue requirement. The CPUC has Utility's procurement of wholesale electricity approved, on a preliminary basis, a starting from the PX and ISO during the height of the ERRA revenue requirement of $2.0 billion for the 2000 - 2001 California energy crisis. With the Utility. exception of a limited right to purchase electricity from third parties beginning in The CPUC has authorized the Utility to file an August 2000, all of the Utility's wholesale electric application to change retail electricity rates at purchases during this period were required to be any time that its forecasts indicate it will face an made exclusively from or through the PX and under-collection of electricity procurement costs ISO markets pursuant to FERC-approved tariffs.

in excess of 5 percent of its prior year's Prior CPUC decisions have determined that such generation and procurement revenues, excluding purchases should be deemed reasonable. In amounts collected for the DWR. The Utility addition, the Utility's complaint against the CPUC currently estimates that its 5 percent threshold Commissioners asserts that the costs of such amount will be approximately $224 million. purchases are recoverable in the Utility's retail 47

rates without further review by the CPUC under Divestiture of Retained Generation the federal filed rate doctrine. However, a CPUC Facilities administrative law judge is asserting jurisdiction to review the reasonableness of the Utility's The California Legislature passed AB 6X in wholesale electric purchases from the PX and January 2001 prohibiting utilities from divesting ISO in the proceeding. A report from the CPUC's their remaining power plants before January 1, Office of Ratepayer Advocates (ORA) regarding 2006. The Utility believes this law does not the Utility's procurement activities for the supersede or repeal existing provisions of covered period is due April 28, 2003. It is AB 1890, California's 1996 electric industry possible this review could result in disallowance restructuring legislation, requiring the CPUC to of certain costs associated with the Utility's establish a market value for the Utility's purchases from the PX and ISO during the remaining generating assets by the end of 2001, 2000 - 2001 period. based on appraisal, sale or other divestiture. The Utility has filed comments on this matter with the Retained GenerationRevenue Requirement CPUC. However, the CPUC has not yet issued a decision.

The CPUC has approved a 2002 revenue requirement of $3 billion for recovery of costs of On January 2, 2002, the CPUC issued a decision generation the Utility retains, including electric finding that AB 6X had materially affected the purchase expenses, depreciation, operating implementation of AB 1890. The CPUC expenses, taxes, and return on investment, based scheduled further proceedings to address the on the net regulatory value as of December 31, impact of AB 6X on the AB 1890 rate freeze for 2000. the Utility and to determine the extent and disposition of the Utility's remaining unrecovered The CPUC has allowed the Utility to recover transition costs. In its November 2002 decision reasonable costs incurred in 2002 for its own regarding surcharge revenues (see "One-Cent, electric generation, subject to reasonableness Three-Cent, and Half-Cent Surcharge Revenues" review in the Utility's 2003 General Rate Case below), the CPUC reiterated that it had yet to (GRC) proceeding. The decision does not change decide when the rate freeze ended and the retail electric rates and the Utility does not disposition of any under-collected costs expect it to have an impact on the Utility's remaining at the end of the rate freeze.

results of operations. Instead, the decision defers consideration of future rate changes until the On January 17, 2002, the Utility filed an CPUC addresses the status of the retail rate administrative claim with the State of California freeze. The CPUC also deferred addressing Victim Compensation and Government Claims recovery of the Utility's past unrecovered Board, or Claims Board, alleging that AB 6X generation-related costs. violates the Utility's statutory rights under AB 1890. The Utility's claim seeks compensation The CPUC is considering the Utility's 2003 for the denial of its right to at least a $4.1 billion retained generation revenue requirement as part market value of its retained generating facilities.

of the Utility's 2003 GRC proceeding. The On March 7, 2002, the Claims Board formally Utility's 2003 GRC application requested an denied the Utility's claim. Having exhausted increase in non-fuel generation revenue remedies before the Claims Board, on requirements of $149 million over the amount September 6, 2002, the Utility filed a complaint authorized for 2002. This requested revenue against the State of California for breach of requirement increases the Utility's estimated fuel contract in the California Superior Court. On and procurement costs recorded in the ERRA January 9, 2003, the Superior Court granted the (see "Approval of Procurement Plan" above), State's request to dismiss the Utility's complaint, and the DWR's power charges. finding that AB 1890 did not constitute a contract. The Utility has 60 days to file an appeal and intends to do so.

48

Direct Access Suspension and Cost interest on under-collections will be assessed at Responsibility Surcbarge the interest rate paid by the DWR on bonds issued to finance electricity purchases.

Until September 2001, California utility customers could choose to buy their electricity from the The Utility does not expect that the CPUC's Utility (bundled customers) or from an implementation of this decision or the level of alternative power supplier through "direct the CRS cap will have a material adverse effect access" service. Direct access customers receive on its results of operations or financial condition.

distribution and transmission service from the Utility, but purchase electricity (generation) from Direct Access Credits their alternative provider. In September 2001, the CPUC, pursuant to AB 1X, suspended the right When the direct access credit was established, of retail end-use customers to choose direct direct access customers paid the full bundled access service, thereby preventing additional rate less a credit based on the Schedule PX customers from entering into contracts to price. Under this methodology, when the purchase electricity from alternative providers. Schedule PX price exceeded the bundled rates, Customers that entered into direct access the direct access customer received a bill credit.

contracts on or before September 20, 2001, were As a result, during the energy crisis, direct access permitted to remain on direct access. customers did not contribute to the Utility's transition cost recovery nor did they pay for In November 2002, the CPUC issued a decision transmission and distribution services. Under the assessing an exit fee, or non-bypassable charge, interim direct access credit methodology in place on direct access customers to avoid a shift of since the PX ceased operations in January 2001, costs from direct access customers to bundled the Utility has calculated the Schedule PX price service customers. using an estimate of its cost of service for its retained generation and the Utility's generation The decision establishes the Cost Responsibility component of the frozen rate for energy Surcharge (CRS) and imposes a cap of $0.027 per provided by the DWR. Beginning January 1, kWh. The CPUC required the utilities to 2003, the Utility reduced this direct access credit implement this surcharge on January 1, 2003. by the additional direct access exit fee of up to The CPUC has indicated that it will establish an the $0.027 per kWh CRS cap.

expedited review schedule to determine whether the cap should be adjusted. The CPUC also has Additionally, direct access customers paid the indicated that it will reach a decision on whether one-cent surcharge in 2001 and 2002, but were this cap should be adjusted, and whether trigger exempt from the three-cent surcharge and mechanisms for adjusting the cap should be half-cent surcharge. In May 2001, the Utility also established, by July 1, 2003. The Utility requested authorization to charge direct access implemented the $0.027 per kWh CRS on customers for the three-cent surcharge. One January 1, 2003. (See "Direct Access Credits" party filed a protest indicating that direct access below.) customers should not pay the three-cent surcharge, nor the one-cent surcharge beginning Funds remitted under the CRS will be applied June 1, 2001. The one-cent surcharge generates first to the DWR, then to the Utility's ongoing approximately $80 million in revenues per year procurement and generation costs. Direct access from direct access customers. The CPUC has not customers who have returned to bundled service yet ruled on this issue. It is unclear how or will be responsible for their share of the whether direct access customers would be unrecovered costs resulting from the CRS. To the reimbursed if the CPUC rules that direct access extent the cap results in an under-collection of customers should not have paid this charge. In DWR charges, the shortfall would have to be November 2002, the CPUC determined that direct remitted to the DWR from bundled customers' access customers should pay a portion of DWR's funds. On an interim basis while the CPUC costs beginning in 2003 to keep bundled examines a long-term plan for financing the CRS, customers indifferent as to the level of direct 49

access. As a result, on January 1, 2003, direct a result, in May 2001, the CPUC authorized the access customers began paying a $0.027 per Utility to collect an additional $0.005 per kWh kWh surcharge, and they no longer pay the surcharge revenue for 12 months to make up for

$0.01 per kWh surcharge. the time lag in collection of the $0.03 per kWh surcharge revenues. Although the collection of On May 31, 2002, the Utility filed its proposal for this "half-cent surcharge" was originally calculating the post-PX direct access credit that scheduled to end on May 31, 2002, the CPUC would continue allowing direct access customers issued a resolution ordering the Utility to to receive a credit for generation-related costs continue collecting the half-cent surcharge until avoided as a result of their self-procurement. further consideration by the CPUC. The Utility Specifically, the Utility proposed that the credit had recorded a regulatory liability for these $0.01 be based on avoided procurement costs. The per kWh and $0.03 per kWh surcharge revenues Utility also proposed to move to bottoms-up when such surcharges exceeded ongoing billing (billing for specific rate components procurement costs and a regulatory liability for rather than a frozen rate) for direct access the $0.005 per kWh surcharge revenues billed customers as quickly as possible. Under bottoms- subsequent to May 31, 2002. These regulatory up billing, direct access customers' rates would liabilities totaled $222 million as of be calculated based on the services they actually September 30, 2002, and $65 million as of take from the Utility, such as transmission and December 31, 2001.

distribution, the fixed transition amount related to the rate reduction bond repayment (if In November 2002, the CPUC approved a applicable), and any non-bypassable charges that decision modifying the restrictions on the use of the CPUC approves including nuclear revenues generated by the surcharges to permit decommissioning and public purpose programs, the revenues to be used for the purpose of as well as the direct access Customer securing or restoring the Utility's reasonable Responsibility Surcharge described above. financial health, as determined by the CPUC. The Consequently, direct access customers would pay CPUC will determine in other proceedings how at least the same non-procurement charges that the surcharge revenues can be used, whether are applicable to bundled customers. there is any cost or other basis to support specific surcharge levels, and whether the The Utility proposed to adjust the direct access resulting rates are just and reasonable. After the credit retroactively to December 28, 2000, using CPUC determines when the AB 1890 rate freeze the Dow Jones Index after January 18, 2001, and ended, the CPUC will determine the extent and to limit the amount of the credit to the price cap disposition of the Utility's under-collected costs, established by the FERC. if any, remaining at the end of the rate freeze. If the CPUC determines that the Utility recovered One-Cent, Three-Cent, and Half-Cent revenues in excess of its transition costs or in Surcbarge Revenues excess of other permitted uses, the CPUC may require the. Utility to refund such excess In the first quarter of 2001, the CPUC authorized revenues.

the Utility to begin collecting energy purchase surcharge revenues totaling $0.04 per kWh In a case currently pending before it relating to (composed of a $0.01 per kWh surcharge the CPUC's settlement with Southern California revenue approved in January and a $0.03 per Edison (SCE), another California IOU, the kWh surcharge revenue approved in March). The Supreme Court of California is considering CPUC ordered the Utility to apply these new whether the CPUC has the authority to enter into rates only to "ongoing procurement costs" and a settlement which allows SCE to recover under-

"future power purchases." collected procurement and transition costs in light of the provisions of AB 1890. The Utility Although the CPUC authorized the $0.03 per cannot predict the outcome of this case or kWh surcharge in March 2001, the Utility did not whether the CPUC or others would attempt to begin collecting the revenues until June 2001. As apply any ruling to the Utility. If the Utility is 50

-I

ordered to refund material amounts to In October 2001, the CPUC reopened the record ratepayers, the Utility's financial condition and in the 1999 GRC to review the Utility's actual results of operations would be materially 1998 capital spending on electric distribution adversely affected. compared with the forecast used to determine 1999 rates. This would result in an adjustment of In December 2002, the CPUC issued a decision the adopted 1998 capital spending forecast level authorizing the Utility to stop tracking amounts to conform to the 1998 recorded level. The related to the $0.01 per kWh and $0.03 per kWh Utility does not expect a material impact on its surcharge revenues as a separate regulatory financial position or results of operations from liability and instead record them as a reduction the remaining proceedings.

of under-collected purchased power costs and transition costs. As a result, in January 2003, the On December 1, 2002, the CPUC issued a Utility filed a letter with the CPUC requesting to decision further modifying the 1999 GRC withdraw its regulatory liability account used to decision that prospectively adopted a track $0.01 per kWh and $0.03 per kWh $10.6 million downward annual adjustment to surcharge revenues in excess of ongoing supervision costs in customer records and procurement costs. collection expenses. There was no material impact on the Utility's financial position or Based on this December 2002 CPUC decision results of operations.

and an agreement between the CPUC and SCE, in which SCE was allowed to use its half-cent 2003 GRC surcharge to offset its DWR revenue requirement, the Utility reversed its $222 million of regulatory In the 2003 GRC, the CPUC will determine the liabilities related to the $0.01 per kWh and $0.03 amount of authorized base revenues the Utility per kWh surcharge revenues and the $0.005 per can collect from ratepayers to recover its basic kWh surcharge revenues during the fourth business and operational costs for gas and quarter of 2002. (Of this amount, $157 million electric distribution operations for 2003 through was originally recorded as a regulatory liability 2005. On November 8, 2002, the Utility during 2002; as such, the reversal of this amount requested a $447 million increase in its electric has no impact on current year earnings). distribution revenue requirements and a

$105 million increase in its gas distribution 1999 GRC revenue requirements, over the current authorized amounts. The Utility also will seek an Through a GRC proceeding, the CPUC authorizes attrition rate adjustment (ARA) increase for 2004 an amount known as "base revenues" to be and 2005. The ARA mechanism is designed to collected from ratepayers to recover the Utility's avoid a reduction in earnings in years between basic business and operational costs for its gas GRCs to reflect increases in rate base and and electric distribution operations. expenses.

The 1999 GRC decision ordered an audit to The electric distribution revenue requirement assess the contribution of the Utility's 1999 increase would not increase overall bundled electric and gas distribution capital additions to electric rates over their current authorized levels.

system reliability, capacity, and adequacy of However, the gas bill for a typical residential service. The audit began in February 2002 and a customer would rise by approximately final report was issued on November 8, 2002. 2.6 percent or $0.99 per month.

The final report concludes, "in general the

[Utility's] 1999 overall capital expenditure Additionally, as directed by the CPUC in the program appears quite acceptable." The final Utility's 2002 retained generation proceeding (see report offers recommendations to improve the "Retained Generation Revenue Requirement" Utility's distribution capital investment process, above), the Utility submitted testimony but recommends no adjustments to the Utility's supporting the costs of operating the Utility's distribution rate base. generation facilities and fuel and purchased 51

power costs. The Utility requested an increase of February 2003, an alternate proposed decision approximately $61 million over the interim 2002 was issued that would grant a $63.5 million retained generation revenue requirement increase to the Utility's annual electric authorized by the CPUC. On October 25, 2002, distribution revenue requirement, and a the CPUC issued a decision ordering the Utility $10.3 million increase to the Utility's annual gas to resume the procurement function on distribution revenue requirement. A final January 1, 2003. That decision also directed the decision is expected to be issued in the first Utility to amend its GRC application to remove quarter of 2003.

certain generation-related fuel and purchased power costs from its GRC and instead to include In the 2003 GRC, the CPUC asked parties to them in another CPUC proceeding. In its GRC, comment on the Utility's need for a 2002 ARA the Utility forecasts a decrease in these costs in proceeding. The Utility informed the CPUC in 2003. This decrease offsets the forecast increase November 2001 that the Utility would need a in costs to operate the Utility's generation 2002 ARA to recover escalating electric and gas facilities. Removing the fuel and purchase power distribution service costs.

from the generation-related revenue requirement set forth in the GRC would result in an increase Cost of CaTital Proceedings in the forecast generation-related revenue requirement of approximately $80 million to Each year, the Utility files an application with the

$90 million. CPUC to determine the authorized rate of return the Utility may earn on its electric and gas On December 17, 2002, the CPUC granted the distribution assets.

Utility's request that the revenue requirement established in the 2003 GRC be effective On November 7, 2002, the CPUC issued a final January 1, 2003, even though the CPUC will not decision in the Utility's 2003 Cost of Capital issue a final decision on the 2003 GRC until proceeding that retained the Utility's return on sometime after that date. common equity (ROE) at the current authorized level of 11.22 percent. This final decision also The Utility cannot predict what amount of increased the Utility's authorized cost of debt to revenue requirements, if any, the CPUC will 7.57 percent from 7.26 percent, and held in authorize for the 2003 through 2005 period. The place the current authorized capital structure of CPUC Commissioner assigned to the 2003 GRC 48 percent common equity, 46.2 percent has adopted a schedule for this proceeding that long-term debt, and 5.8 percent equity. The final includes a target date for a final decision of decision also holds open the case to address the February 5, 2004. impact on the Utility's ROE, costs of debt and preferred stock, and ratemaking capital structure 2002 ARA Request of the implementation and financing of a bankruptcy plan of reorganization. The Utility is In April 2002, the CPUC conditionally authorized required to file an advice letter within 30 days of a request by the Utility for interim attrition relief completing any such financing to request and made any attrition relief ultimately granted authority to true up its test year 2003 ratemaking effective as of April 22, 2002. In June 2002, the capital structure, long-term debt and preferred Utility filed its 2002 ARA application, requesting stock cost, risks, and ROE. The Utility does not a $76.7 million increase to its annual electric expect a material impact on the Utility's financial distribution revenue requirement, and a position or results of operations from the

$19.5 million increase to its annual gas remaining proceedings.

distribution revenue requirement. In December 2002, a proposed decision was issued FERC Prospective PriceMitigation Relief that would deny this request The Utility filed comments in late December 2002 arguing that In response to the unprecedented increase in the proposed decision was based on a wholesale electricity prices during 2000 and fundamental misunderstanding of the facts. In 2001, the FERC issued a series of orders in the 52

spring and summer of 2001 and July 2002 aimed refund methodology are appropriate, such at mitigating future extreme wholesale energy decisions could materially increase or decrease prices. These orders established a cap on bids the amount of generator daims for which the for real-time electricity and ancillary services of Utility is determined to be liable. The Utility

$250 per megawatt-hour (MWh) and established cannot predict the ultimate amount of generator various automatic mitigation procedures. claims for which it could be liable. The Utility Recently, the FERC proposed to adopt a safety also sold generation into the ISO and PX markets net bid cap as part of the mitigation plan for in the relevant time period. The amount of wholesale energy markets and has requested generator claims for which the Utility is comments on the appropriate value for such a determined to be liable would be net of any bid cap. amounts owed to the Utility for such sales. The Utility cannot predict when the FERC will issue a Also, in June and July 2001, the FERC's chief decision, nor can it predict whether a refund will administrative law judge conducted settlement be ordered or the amount the Utility might negotiations among power sellers, the State of receive.

California, and the California lOUs in an attempt to resolve disputes regarding past electric sales. FERC TransmissionRate Cases Various parties, including the Utility and the State of California, are seeking up to $8.9 billion in Electric transmission revenues and both refunds for electricity overcharges on behalf of wholesale and retail transmission rates are buyers. The negotiations did not result in a regulated by the FERC. On January 29, 2003, the settlement, but the judge recommended that the FERC approved a settlement that allows the FERC conduct further hearings to determine Utility to recover in electric transmission rates possible refunds and what the power sellers and $292 million on an annual basis from March 31, buyers are each owed. On December 12, 2002, a 1998, until October 29, 1998, and $316 million FERC administrative law judge issued an initial on an annual basis from October 30, 1998, until decision finding that power companies May 30, 1999. During that period, somewhat overcharged the utilities, the State of California higher rates were collected, subject to refund. As and other buyers from October 2, 2000 to a result of this settlement, the Utility will refund June 2001 by $1.8 billion, but that California $30 million it had accrued for potential refunds buyers still owe the power companies $3 billion, related to the 14-month period ended May 30, leaving $1.2 billion in unpaid bills. The time 1999. The transmission rates charged to electric period reviewed in the FERC hearings excludes retail and new wholesale transmission customers the claims for refunds for overcharges that are adjusted for other transmission revenue occurred before October 2, 2000, and after credits related to ISO congestion management June 2001 when the DWR entered into contracts charges and other transmission-related services to buy electricity. Additional hearings are billed by the ISO and remitted to the Utility as a scheduled to conclude in February 2003. transmission owner.

The Utility has recorded $1.8 billion of generator The Utility currently has other transmission rate claims made in its bankruptcy case as Liabilities cases pending with the FERC including:

Subject to Compromise. If the FERC

• An application that would allow the Utility administrative law judge's initial recommendation to recover $545 million in electric retail is upheld by the FERC, these claims would be transmission rates annually. Filed on reduced to approximately $1 billion based on January 13, 2003, the 44 percent increase the re-calculation of market prices according to over the revenue requirement currently in the refund methodology recommended in the effect is mainly attributable to significant initial decision. After the FERC considers any capital additions made to the Utility's additional evidence that may be presented, if the transmission system to accommodate load FERC determines that time periods before growth, to maintain the infrastructure, and October 2, 2000, should be considered, or that to ensure safe and reliable service. In additional market transactions or a different 53

addition, the request includes a 15-year On August 5, 2002, the FERC ruled that the useful life for transmission plant coming Utility should refund to TO Tariff customers the into service in 2003 and a return on scheduling coordinator costs that the Utility equity of 13.5 percent. The January 13 collected from them. In November 2002, the filing date will allow proposed rates to go FERC denied the Utility's request for rehearing.

into effect, subject to refund, no later than On December 9, 2002, the Utility appealed the August 13, 2003; and FERC's decision in the U.S. Court of Appeals for the D.C. Circuit. In the absence of an order from A proposal for the FERC to increase the the FERC granting recovery of these costs in the Utility's electricity and transmission-related TRBA, the Utility has made accounting entries to rates charged to the WAPA. The majority reflect the SC costs as accounts receivable under of the requested increase is related to the Scheduling Coordinator Services (SCS) Tariff passing through market electricity prices billed to the Utility by the ISO and others described below.

for services, which apply to WAPA under In January 2000, the FERC accepted a filing by a pre-existing contract between the Utility the Utility to establish the SCS Tariff. The SCS and WAPA. The FERC denied this request, Tariff was filed to serve as an alternative as well as a request for a rehearing. The mechanism for recovery of the SC costs from Utility has appealed the denial of its existing wholesale customers if the Utility was request for a rehearing to the U.S. Court ultimately unable to recover these costs in the of Appeals for the D.C. Circuit. Pending a TRBA. The FERC also conditionally granted the decision from the Court, until Utility's request that the SCS Tariff be effective December 31, 2004, the date the WAPA retroactive to March 31, 1998. However, the contract expires, the Utility will continue FERC suspended the procedural schedule until to calculate WAPA's rates on a yearly basis the final decision was issued regarding the using the formula specified in WAPA's inclusion of SC costs in the TRBA. In contract. Any revenue shortfall or benefit September 2002, the Utility filed a notice with resulting from this contract is included in the FERC indicating its intent to request that the rates through the end of the contract FERC resume the SCS Tariff proceeding if the period as a purchased power cost. The request for rehearing of the FERC's August 5 Utility cannot estimate the difference order was not granted. For the period beginning between its cost to meet its obligations to April 1998 through December 31, 2002, the WAPA and revenues it receives from Utility transferred $107 million of scheduling WAPA because both the purchase price coordinator costs from the TRBA to accounts and the amount of energy that WAPA will receivable net of a $66 million reserve for need from the Utility through the end of potential uncollectible costs. The Utility also has the contract are uncertain.

disputed approximately $27 million of these Scheduling CoordinatorCosts costs as incorrectly billed by the ISO. Any refunds that ultimately may be made by the ISO The Utility serves as the scheduling coordinator would offset the accounts receivable and to schedule transmission with the ISO for the corresponding reserve.

Utility's existing wholesale transmission The Utility does not expect the outcome of this customers. The ISO bills the Utility for providing certain services associated with these contracts. proceeding to have a material adverse effect on These ISO charges are referred to as the its results of operations or financial condition.

"scheduling coordinator (SC) costs." These costs Gas Accord 11 historically have been tracked in the transmission revenue balancing account (TRBA) in order to In 1998, the Utility implemented a ratemaking recover these costs from retail and new pact called the Gas Accord, separating its gas wholesale transmission customers (TO Tariff transportation and storage services from its customers). distribution services, and changing the terms of 54

service and rate structure for gas transportation. 12.9 percent increase in the Utility's revenue The Gas Accord allows residential and small requirement and a 13.4 percent return on equity.

commercial customers (core customers) to purchase gas from competing suppliers, The existing gas transportation and storage rates establishes an incentive mechanism whereby the will continue until the CPUC approves such Utility recovers its core procurement costs, and changes. The Gas Accord 11 proposal includes establishes gas transportation rates through 2002 rates set based on a demand or throughput and gas storage rates through March 2003. Under forecast basis. In addition it proposes that, at the the Gas Accord, the Utility is at-risk for recovery beginning of the adopted Gas Accord 11 of its gas transportation and storage costs and agreement period, a contract extension and an does not have regulatory balancing account open season be held for any uncontracted protection for over- or under-collections of capacity rights. The Utility may experience a revenues. Under the Gas Accord, the Utility sells material reduction in operating revenues (1) if a portion of the transportation and storage the Utility were unable to renew or replace capacity at competitive market-based rates. existing transportation contracts at the beginning Revenues are sensitive to changes in the or throughout the Gas Accord II period, (2) the weather, natural gas fired generation and price Utility were to renew or replace those contracts spreads between two delivery or pricing points. on less favorable terms than adopted by the CPUC, or (3) overall demand for transportation On October 9, 2001, the Utility asked the CPUC and storage services were less than adopted by to extend the terms and conditions of the the CPUC in setting rates. In any of these cases, existing Gas Accord for two years and to the Utility's financial condition and results of maintain current gas transportation and storage operations could be adversely affected.

rates during the extension.

The Utility cannot predict what the outcome of In August 2002, the CPUC approved a settlement this litigation will be, or whether the outcome agreement among the Utility and other parties will have a material adverse effect on its results that provided for a one-year extension of its of operations or financial condition.

existing gas transportation and storage rates. The settlement also provided for a one-year El Paso Capacity Decision extension of terms and conditions of service, including the Core Procurement Incentive In May 2002, the FERC directed El Paso Natural Mechanism (for further discussion see "Utility Gas Company (El Paso) to change the way it Natural Gas Commodity Price Risk"), as well as allocates space on its pipeline. The order rules governing contract extensions and an open required shippers east of California with capacity season for new contracts. The Gas Accord II rights on El Paso's pipeline to convert their settlement left open to subsequent litigation the capacity rights from unlimited "full requirement" issues raised in the application in so far as they to a limited contract demand amount of firm relate to the second year of the two-year capacity. These shippers had to decide by application. July 31, 2002, how much El Paso capacity they would need in demand contracts and how much In October 2002, the assigned CPUC capacity they would give up.

administrative law judge issued a ruling that granted, in part, the Utility's motion to postpone In July 2002, the CPUC required California lOUs the procedural schedule for litigation of the to sign up for El Paso pipeline capacity given up unresolved issues. In January 2003, the Utility by the shippers and not subscribed to by filed an amended application proposing to replacement shippers serving California. The permanently retain the Gas Accord market CPUC pre-approved such costs as just and structure, and requested a $55 million increase in reasonable. The decision stated that this the Utility's gas transmission rates for 2004 and requirement would spread El Paso reservation storage rates for the period from April 1, 2004, to charges over as many ratepayers as possible to March 31, 2005. This request represents a 55

minimize the impact on any particular utility's resolution also ordered the Utility to continue to customers. treat Transwestern capacity costs as it had prior to the July 2002 CPUC decision. Recovery of The decision also addressed current capacity Transwestern costs not currently authorized is issues. It ordered the utilities to retain their being addressed in Phase 11 of the proceeding.

current capacity levels on any interstate pipeline The Utility does not expect the outcome of this and to sell any excess capacity to a third party matter to have a material adverse impact on its under short-term capacity release arrangements. financial position or results of operations.

To the extent the utilities comply with the decision, they will be able to fully recover their Rate Reduction Bonds costs associated with existing capacity contracts.

California's electric industry restructuring law In Phase II of this proceeding, the CPUC is (AB 1890) required that retail electric rates for addressing other issues that relate to these residential and small commercial customers be proposed rules, including (1) cost allocation of reduced by 10 percent and frozen at that level the El Paso capacity among the Utility's until the earlier of March 31, 2002, or when the customers, (2) short-term capacity releases, and Utility fully recovered certain costs associated (3) details about the guaranteed rate recovery of with the transition to a deregulated energy the utilities' costs for subscription to interstate market.

pipeline capacity. Phase II hearings are scheduled for the end of April 2003. To pay for the 10 percent rate reduction, the legislation authorized the issuance of rate Since the July CPUC decision, the Utility has reduction bonds to be repaid by residential and signed contracts for capacity on El Paso totaling small commercial customers through the approximately $50.8 million beginning collection of a separate non-bypassable charge November 2002 through December 2007, called the Fixed Transition Amount (FTA). The assuming no contracts set to expire before the Utility sold its rights to collect FTA charges to its end of 2007 are extended. The Utility has filed subsidiary PG&E Funding LLC for $2.9 billion in with the CPUC to recover both prepayments cash. To fund the purchase, PG&E Funding LLC made to El Paso and ongoing capacity costs on issued $2.9 billion of rate reduction bonds (see the El Paso and the Transwestern Pipeline discussion of "Rate Reduction Bonds" in Note 5 Company (Transwestern) pipelines. Under a of the Notes to the Consolidated Financial previous CPUC decision, the Utility could not Statements). The bonds allow for the rate recover any costs paid to Transwestem for gas reduction by lowering the carrying cost on a pipeline capacity through 1997. The Gas Accord portion of the Utility's transition costs and by (see "Gas Accord II" above) provided for partial spreading recovery of that reduction over the life recovery of Transwestern costs during the period of the bonds.

1998 through 2002. However, because of the El Paso decision, the Utility may be authorized to Because of the 10 percent rate reduction, the recover its future gas pipeline capacity amount of revenue the Utility had available in its purchases, which could result in additional frozen rates to recover its transition costs was revenues to recover costs of approximately reduced. Before the first quarter of 2002, to the

$82 million over the remaining contract period extent that transition costs were not recovered that ends in March 2007. because of the 10 percent rate reduction, the Utility deferred these transition costs through the On December 19, 2002, the CPUC issued a rate reduction bond regulatory asset (RRBRA).

resolution that would delay the Utility's recovery The RRBRA will be recovered through future FTA of some of these costs. The resolution grants the charges.

Utility's request to recover in rates El Paso capacity costs and prepayments made to El Paso, In the first quarter of 2002, the Utility stopped subject to reallocation between customers in deferring transition costs into the RRBRA and Phase 11 of the proceeding. However, the began amortizing the balance of the RRBRA 56

concurrent with the amortization of the rate approximately $106 million. The CPUC has reduction bonds debt. The Utility recorded delayed action on these proceedings and the amortization expense of $290 million for the 12 Utility has not included any earnings associated months ended December 31, 2002. The Utility with incentives in the Utility's Consolidated recorded deferred transition costs of $458 million Statements of Operations.

for the 12 months ended December 31, 2001.

The balance of the RRBRA was $1,346 million at On March 13, 2002, an administrative law judge December 31, 2002, and $1,636 million at for the CPUC requested comments on whether December 31, 2001. incentives adopted for pre-1998 energy efficiency programs should be reduced or eliminated for The proceeds of the rate reduction bonds claims in future years. Out of the total included amounts sufficient to pay income taxes $106 million in shareholder incentives claimed that would be levied on future FTA revenues. by the Utility for its 2002, 2001, and 2000 AEAP The Utility benefited from the receipt of this cash filings, $74 million is related to pre-1998 energy up front as it reduced the overall level of efficiency programs. The CPUC has not yet ruled financing the Utility was required to maintain. on the comments.

Before the first quarter of 2002, the financing cost benefit was credited to ratepayers through a The Utility cannot predict the outcome of these reduction in the amount of transition costs that proceedings, or whether the outcome will have a were deferred into the RRBRA. When the Utility material adverse effect on its results of stopped deferring transition costs into the operations or financial condition.

RRBRA, the Utility began crediting this benefit to a regulatory balancing account. The balance Baseline Allowance Increase credited to residential and small commercial customers through this account was $102 million In April 2002, the CPUC required the Utility to at December 31, 2002 and $17 million at increase baseline allowances for certain December 31, 2001. residential customers by May 1, 2002. An increase to a customer's baseline allotment Annual EarningsAssessment Proceedingfor increases the amount of their monthly usage that Energ Efficiency ProgramActivities is covered under the lowest possible rate and is exempt from surcharges. The CPUC deferred The Utility administers general and low-income consideration of corresponding rate changes until energy efficiency programs, and has been a later phase of the proceeding and ordered the authorized to earn incentives based on a portion utilities to track the under-collections associated of the net present value of the savings achieved with their respective baseline quantity changes in by the programs, incentives based on an interest-bearing balancing account. The Utility accomplishing certain tasks, and incentives based estimates the annual revenue shortfall to be on expenditures. Each year the Utility files an approximately $96 million for electric and earnings claim in the Annual Earnings $6 million for gas. The Utility is charging the Assessment Proceeding (AEAP), a forum for electric-related shortfall against earnings because stakeholders to comment on, and for the CPUC it cannot predict the outcome of the second to verify, the Utility's claim. On March 21, 2002, phase of the proceeding, nor can it conclude the CPUC eliminated the opportunity for that recovery of the electric-related balancing shareholder incentives in connection with the account is probable. The total electric revenue California utilities' 2002 energy efficiency shortfall for the period May through programs. This decision does not preclude the December 2002 was $69.8 million.

opportunity to recover shareholder incentives in connection with previous years' energy efficiency Issues that may be resolved during the second programs. phase of the proceeding in early 2003 include items that could involve additional revenues at In May 2002, 2001, and 2000, the Utility filed its risk such as demographic revisions to baseline annual applications claiming incentives of allowances, special allowances, and changes to 57

baseline territories or seasons. The Utility anticipates recovering $7.3 million in estimated additional annual revenue shortfalls CPUC-jurisdictional revenue requirements for from this second phase, if adopted, of Humboldt Bay Unit 3 SAFSTOR (a mode of

$79.6 million for electric service and $11 million decommissioning) operating and maintenance for gas service, plus $11.6 million in costs, and escalation associated with that amount administration costs spread out over three to five in 2004 and 2005. The Utility proposes years. Included in this amount is an estimated continuing to collect the revenue requirement

$18 million annual shortfall resulting from a through a charge in electric rates, and to record settlement allowing common-area electric the revenue requirement and the associated accounts to switch from residential to revenues in a balancing account. Until post-rate commercial rates. The settlement, approved by freeze ratemaking is implemented, the increase the CPUC on January 16, 2003, is designed to in revenue requirements would reduce the allow common-area accounts to avoid amount of revenues available to offset electric disproportionately high rate increases caused by generation costs.

the five-tiered residential electric surcharges adopted in June 2001. The new five-tiered The ORA filed testimony with the CPUC that residential rate structure resulting from the $0.03 included lower estimates on contingencies, per kWh average surcharge assesses surcharges escalation rates and the cost of disposal of for usage above 130 percent of a customer's low-level radioactive wastes, and a higher baseline allowance. Because most of the usage estimate for returns on investments in the of large common area accounts falls within the Decommissioning Trusts. If ORA's estimates were highest rate tiers, these accounts pay adopted, the Utility would not need to make any disproportionately high bills as a result of this new contributions to the Decommissioning rate design. By contrast, the Utility's surcharges Trusts for the years 2003 through 2005, since the for commercial customers do not vary based on current amounts in the Decommissioning Trusts usage levels. As with the baseline quantity would be adequate to pay for expected changes from the first phase, the CPUC deferred decommissioning activities. The CPUC held common area cost allocation and rate design hearings in September 2002 and is expected to issues to the second phase. reach a final decision during April 2003.

The Utility cannot predict what the outcome of ADDITIONAL SECURITY MEASURES the second phase of the proceeding will be, nor can it conclude that recovery of the electric Since the September 11, 2001, terrorist attacks, baseline related balancing account is probable. PG&E Corporation and the Utility have been Any electric revenue shortfalls will continue to working to assess the need for physical security be charged to earnings and will reduce revenue upgrades at critical facilities. Various federal available to recover previously written-off under- regulatory agencies have issued orders requiring collected purchased power costs and transition additional safeguards, including a May 2002 costs. Nuclear Regulatory Commission, or NRC, order.

The NRC order required decommissioned nuclear NVuclear Decommissioning Cost Triennial facilities, such as the Utility's Humboldt Bay ProceedingApplication Power Plant, to implement interim security compensatory measures. Facilities affected by In March 2002, the Utility filed an application to PG&E Corporation's and the Utility's assessments increase the Utility's nuclear decommissioning include generation facilities, transmission revenue requirements for the years 2003 through substations, and gas transmission facilities. The 2005. The Utility seeks to recover $24 million in security upgrades will require additional capital revenue requirements relating to the Diablo investment and an increased level of operating Canyon Nuclear Decommissioning Trusts and costs. However, neither PG&E Corporation nor

$17.5 million in revenue requirements relating to the Utility believes these costs will have a the Humboldt Bay Power Plant material impact on their consolidated financial Decommissioning Trusts. The Utility also position or results of operations.

58

RISK MANAGEMENT ACllvrEES

• An option contract provides the right, but not the obligation, to buy or sell the PG&E Corporation and the Utility are exposed to underlying asset at a predetermined price various risks associated with their operations, the in the future.

marketplace, contractual obligations, financing arrangements and other aspects of their business. PG&E Corporation uses derivatives for both PG&E Corporation and the Utility actively non-trading and trading (i.e., speculative) manage these risks through risk management purposes. The Utility uses derivatives for programs. These programs are designed to non-trading purposes only.

support business objectives, minimize costs, discourage unauthorized risk, and reduce the PG&E Corporation and the Utility may use volatility of earnings and manage cash flows. At energy and financial derivatives and other PG&E Corporation and the Utility, risk instruments and agreements to mitigate the risks management activities often include the use of associated with an asset (e.g., the natural energy and financial derivative instruments and position embedded in asset ownership and other instruments and agreements. regulatory arrangements), liability, committed transaction, or probable forecasted transaction.

These derivatives include forward contracts, Additionally, PG&E Corporation may engage in futures, swaps, options, and other contracts. trading activities for purposes of generating

• A forward contract is a commitment to profit, gathering market intelligence, creating purchase or sell a fixed amount of a liquidity, and maintaining a market presence.

These instruments are used in accordance with commodity at a specified future date at a approved risk management policies adopted by a specified price; senior officer-level risk oversight committee.

• A futures contract is a standardized Derivative activity is permitted only after the risk commitment, traded on an organized oversight committee approves appropriate risk exchange, to purchase or sell a fixed limits for such activity. The organizational unit amount of a commodity at a specified proposing the activity must successfully future date at a specified price; demonstrate that there is a business need for

• A swap contract is an agreement between such activity and that the market risks will be two counterparties to exchange cash adequately measured, monitored, and controlled.

flows in the future based on changes in the underlying commodity or index; and 59

The activities affecting the estimated fair value of balance, included in net price risk management trading activities and the non-trading activities assets and liabilities, are presented below.

(in millions) Year Ended December 31, 2002 2001 Fair values of trading contracts at beginning of period ...... 58 $ 199 Net (gain) loss on contracts settled during the period ....... (121) (296)

Fair value of new contracts when entered into ........... 2 -

Changes in fair values attributable to changes in valuation techniques and assumptions ...................... (12)

Other changes in fair values....................... 51 155 Fair values of trading contracts outstanding at end of period (22) 58 Fair value of non-trading contracts at the end of the period ... (27o) 63 Net Price Risk Management Assets (Liabilities) at end of period (292) 121 Amounts reclassified as net price risk management assets (liabilities) held for sale ......................... (377) 55 Net price risk management assets (liabilities) reported on the Consolidated Balance Sheets ...................... $ 85 $ 66 The changes in fair values attributable to When market data is not available, PG&E changes in valuation and assumptions, as Corporation uses its forward price curve reported in the table above, are composed of a methodology described in Note 1 of the Notes to

$14 million loss related to PG&E NEG's the Consolidated Financial Statements.

implementation of a new methodology for estimating forward prices in illiquid periods, for The gross mark-to-market valuation is then which price information is not readily available, adjusted for the time value of money, and a $2 million gain related to changes in creditworthiness of contractual counterparties, assumptions used to value transportation market liquidity in future periods, and other contracts. This change in forward prices is adjustments necessary to determine fair value.

described more fully in Note 1 of the Notes to Most of PG&E Corporation's risk management the Consolidated Financial Statements. models are reviewed by or purchased from third-party experts in specific derivative applications.

PG&E Corporation estimates the gross mark-to-market value of its non-trading and The following table shows the fair value of trading contracts at December 31, 2002, using PG&E Corporation's trading contracts grouped by the midpoint of quoted bid and ask prices, maturity at December 31, 2002.

where available.

(in mill1ons) Fair Value of Trading Contracts (

Maturity Maturity Maturity Maturity Total Lessthan One-Three Four-Five in Excess of Fair One Year Years Years Five Years Value Source of Prices Used in Estimating Fair Value Actively quted markets 2( .$...............$ 6 $ 10 $ - $ - $ 16 Provided by other external sources (26) 7 (13) (3) (35)

Based on models and other valuation methods . (23) (30) (15) 65 (3)

Total Mark-to-Market ........... $ (43) $ (13) $ (28) $ 62 $ (22)

"' Exdudes all non-trading contracts, including non-trading contracts that receive mark-to-market accounting treatment.

' Actively quoted markets are exchanged traded quotes.

3) In many cases, these prices are an input into option models that calculate a gross mark-to-market value from which fair value is derived.

60

The amounts disclosed above are not indicative Also described below is the value-at-risk of likely future cash flows. The future value of methodology, which is PG&E Corporation's and trading contracts may be impacted by changes in the Utility's method for assessing the prospective underlying valuations, new transactions, market risk that exists within a portfolio for price risk.

liquidity, and PG&E Corporation's risk management portfolio needs and strategies. Utility Electric Commodity Price Risk Market Risk Purchased Power Market risk is the risk that changes in market In compliance with regulatory requirements, the conditions will adversely affect earnings or cash Utility manages commodity price risk flow. independently from the activities in PG&E Corporation's unregulated businesses. The Utility PG&E Corporation categorizes market risks as also reports its commodity price risk separately price risk, interest rate risk, foreign currency risk, for its electric and natural gas businesses.

and credit risk. These market risks may impact PG&E Corporation's and its subsidiaries' assets Since January 2001, the DWR has been and trading portfolios. Immediately below is an responsible for procuring electricity required to overview of PG&E Corporation's market risks, cover the Utility's net open position. The Utility followed by detailed descriptions of the market bills its customers for these DWR electricity risks and explanations as to how each of these purchases and remits amounts collected to the risks are managed. DWR based on their CPUC approved revenue requirement. To the extent that the Utility's

• Price risk results from the Utility's or electricity rates remain frozen, and the CPUC PG&E NEG's exposure to the impacts of increases the portion of the DWR's revenue market fluctuations in price and requirement allocated to the Utility's customers transportation costs of commodities such to cover adverse market price changes or other as electricity, natural gas, other fuels, and factors, the Utility has commodity price risk. The other energy-related products; Utility is exposed to price risk to the extent that

• Interest rate risk primarily results from the cost of new electricity purchases increases, exposure to the volatility of interest rates or the revenue from new wholesale sales as a result of financing or refinancing decreases.

through the issuance of variable-rate and fixed-rate debt; The DWR's authority to enter into new electricity purchase contracts expired January 1, 2003.

. Foreign currency risk results from SB 1976 and CPUC orders required the California exposure to volatilities in currency rates; IOUs, including the Utility, to resume and responsibility for procuring the electricity to meet

• Credit risk results from exposure to the residual net open position by January 1, counterparties who may fail to perform 2003.

under their contractual obligations.

On December 19, 2002, the CPUC issued an Price Risk interim opinion granting the Utility authority to enter into contracts designed to hedge the Price risk is the risk that changes in primarily residual net open position through the first commodity market prices will adversely affect quarter of 2004. The CPUC's interim opinion also earnings and cash flows. Below are descriptions established a maximum annual procurement of the Utility's and PG&E NEG's specific price disallowance equal to twice the Utility's annual risks. administrative costs of managing procurement activities, including the administration and dispatch of electricity associated with DWR 61

allocated contracts. However, the Utility can purchased electric generation costs. For this provide no assurance that the CPUC will not reason, the Utility is exposed to price risk to the increase or eliminate this maximum annual extent that the cost of nuclear fuel increases.

procurement disallowance in the future. Such a change would increase the Utility's exposure to Utility NaturalGas Commodity Price Risk electric commodity price risk.

Through 2003, the Core Procurement Incentive The residual net open position is expected to Mechanism (CPIM) determines how much of the increase over time due to periodic expirations of cost of procuring natural gas for its customers existing and DWR allocated procurement may be included in the Utility's natural gas contracts. The Utility can provide no assurance procurement rates. Under the CPIM, the Utility's that electricity will continue to be available for procurement costs are compared to an aggregate purchase in quantities sufficient to satisfy the market-based benchmark based on a weighted residual net open position as these or other average of published monthly and daily natural events occur. Even if the Utility were able to gas prices at the points where the Utility purchase electricity in quantities sufficient to typically purchases natural gas. If costs fall satisfy the residual net open position, it would within a range, or tolerance band currently be exposed to wholesale electricity commodity 99 percent to 102 percent, around the price fluctuations and uncertain commercial benchmark, they are considered reasonable and terms. may be fully recovered in customer rates.

Ratepayers and shareholders share equally the Conversely, the amount of energy provided by costs and savings outside the tolerance band.

the DWR contracts will likely result in significant excess electricity during various periods, which In addition, the Utility has contracts for the Utility will be required to attempt to sell on transportation capacity on various natural gas the open market. pipelines. A recent CPUC decision found that the Utility's acquisition of additional interstate Nuclear Fuel transportation capacity was reasonable and that all interstate transportation capacity already held The Utility has purchase agreements for nuclear by the Utility was also reasonable. A future fuel components and services for use in decision will allocate the cost of the operating the Diablo Canyon generating facility. transportation capacity between customer groups The Utility relies on large, well-established and will also determine the date on which all international producers for its long-term transportation capacity costs held by the Utility agreements in order to diversify its commitments prior to July 2002 will be recoverable.

and ensure security of supply. Pricing terms are also diversified, ranging from fixed prices to base Under the Gas Accord, shareholders are at risk prices that are adjusted using published for any revenues from the sale of capacity on the information. In January 2002, the U.S. Utility's gas transmissions and storage facilities.

International Trade Commission imposed tariffs Under the Gas Accord, the Utility sells a portion of up to 50 percent on imports from certain of the pipeline and storage capacity at countries providing nuclear fuel. If these tariffs competitive market-based rates. Revenues are remain in place, the Utility's nuclear fuel costs generally lower when throughput volumes are may rise because there are a limited number of lower than expected and when the price spreads suppliers in the world for such fuel. The Utility's between two delivery points narrow. In ratemaking for retained generation is cost-of- August 2002, the CPUC approved a settlement service-based; however, to the extent that the agreement between the Utility and other parties Utility's electricity rates remain frozen, changes in that provided for a one-year extension of the the cost of nuclear fuel would impact the Utility's existing gas transmission and storage amount of revenues the Utility has available to rates and terms and conditions of service recover its previously written-off under-collected through the end of 2003. (The Gas Accord was 62

originally scheduled to expire on December 31, volatility, market liquidity, and a specified 2002.) For further discussion, see "Gas Accord holding period. This technique uses historical II" in the "Regulatory Matters" section of the price movements data and specific, defined MD&A. mathematical parameters to estimate the characteristics of and the relationships between PG&E NEG PriceRisk components of assets and liabilities held for price risk management activities. PG&E PG&E NEG is exposed to price risk from its Corporation therefore uses the historical data for portfolio of proprietary trading contracts and its calculating the expected price volatility of its portfolio of electric generation assets and supply portfolio's contractual positions to project the contracts that serve wholesale and industrial likelihood that the prices of those positions will customers, and various merchant plants currently move together.

in development and construction.

The value-at-risk model includes all of PG&E As described above, PG&E NEG is in the process Corporation's and the Utility's commodity of reducing and unwinding its trading positions. derivatives and other financial instruments over Additionally, asset hedge positions associated the entire length of the terms of the transactions with the merchant plants will either remain with in the trading and non-trading portfolios. PG&E the assets or be terminated. PG&E NEG has Corporation's and the Utility's value-at-risk significantly reduced their energy trading calculation is a dollar amount reflecting the operations in an ongoing effort to raise cash and maximum potential one-day loss in the fair value reduce debt. PG&E NEG's objective is to limit its of their portfolios due to adverse market asset trading and risk management activities to movements over a defined time horizon within a only what is necessary for energy management specified confidence level. This calculation is services to facilitate the transition of PG&E NEG's based on a 95 percent confidence level, which merchant generation facilities through their sale, means that there is a 5 percent probability that transfer, or abandonment process. PG&E NEG PG&E Corporation's portfolios will incur a loss in will then further reduce and transition to only value in one day at least as large as the reported retain limited capabilities to ensure fuel value-at-risk. For example, if the value-at-risk is procurement and power logistics for PG&E calculated at $5 million, there is a 95 percent NEG's retained independent power plant probability that if prices moved against current operations. positions, the reduction in the value of the portfolio resulting from such one-day price Value-at-Risk movements would not exceed $5 million. There would also be a 5 percent probability that a PG&E Corporation and the Utility measure price one-day price movement would be greater than risk exposure using value-at-risk and other $5 million.

methodologies that simulate future price movements in the energy markets to estimate the The following table illustrates the potential probability of future potential losses. Price risk is one-day unfavorable impact for price risk as quantified using what is referred to as the measured by the value-at-risk model, based on a variance-covariance technique of measuring one-day holding period. A two-year comparison value-at-risk, which provides a consistent of daily value-at-risk is included in order to measure of risk across diverse energy markets provide context around the one-day amounts.

and products. This methodology requires the The high and low valuations represent the selection of a number of important assumptions highest and lowest of the values during 2002.

including a confidence level for losses, price 63

The average valuation repiresents the average of value-at-risk levels will eventually peak and start the values during; 2002. to decrease because, as previously discussed, PG&E NEG is in the process of reducing and Year Ended unwinding its trading positions. Additionally, (in millions) Dtveember 31, December 31, 2002 asset hedge positions associated with the 21)02 2(001 Average Agh Low merchant plants will either remain with the Utility assets or be terminated. See the discussion above Non-trading in the MD&A's "Liquidity and Financial activities 1) $ 4.0 $ 3.6 $ 2.1 S 5.8 $ 0.3 Resources - PG&E NEG" section for further PG&E NEG Trading activities 8.2 5.8 5.2 9.7 2.1 information regarding PG&E NEG's current Non-trading financial situation.

activities:

Non-trading Interest Rate Risk contracts that receive mark-to-market Interest rate risk is the risk that changes in accounting interest rates could adversely affect earnings or treatment (2) 2.7 - 2.9 3.9 2.1 cash flows. Specific interest rate risks for PG&E Non-trading Corporation and the Utility include the risk of contracts increasing interest rates on working capital accounted for as hedges (" 9.4 10.3 12.5 18.6 9.4 facilities, variable rate tax-exempt pollution controltbonds. and other variable rate debt.

°" Includes the Utility's gas portfolio only, as this represents the Utility's only commodity price risk through year end 2002. PG&E Corporation may use the following interest (2) Includes derivative power and fuels contracts that do not rate instruments to manage its interest rate qualify under the SFAS No. 133 normal purchases and exposure: interest rate swaps, interest rate caps, normal sales exception and do not qualify to be floors, or collars, swaptions, or interest rate accounted for as cash flow hedges. forward and futures contracts. Interest rate risk 5' Includes only the risk related to the derivative instruments that serve as hedges and does not include sensitivity analysis is used to measure interest the related underlying hedged item. Any gain or loss on rate risk by computing estimated changes in cash these derivative commodity instruments would be flows as a result of assumed changes in market substantially offset by a corresponding gain or loss on interest rates. At December 31, 2002, if interest the hedged commodity positions, which are not rates changed by 1 percent for all variable rate included.

debt at PG&E Corporation and the Utility, the change would affect net income by Value-at-risk has several limitations as a measure approximately $35 million for PG&E Corporation of portfolio risk, including, but not limited to, and $33 million for the Utility, based on variable underestimation of the risk of a portfolio with rate debt and hedging derivatives and other significant options exposure, inadequate interest rate-sensitive instruments outstanding.

indication of the exposure of a portfolio to extreme price movements, and the inability to The table included above in this MD&A's address the risk resulting from intra-day trading Commitments and Capital Expenditures section activities. Value-at-risk also does not reflect the provides the maturity of the carrying amounts significant regulatory and legislative risks and the related weighted average interest rates currently facing the Utility or the risks relating to on PG&E Corporation's interest bearing the Utility's bankruptcy proceedings.

securities, by expected maturity dates.

PG&E NEG's value-at-risk levels have increased Foreign Currency Risk at December 31, 2002, as compared to levels at December 31, 2001, due to strong prices and Foreign currency risk is the risk of changes in increased market volatility across all commodities value of pending financial obligations in foreign in 2002. It is expected that PG&E NEG's currencies in relation to the U.S. dollar.

64

PG&E Corporation and the Utility are exposed to and the Utility's overall exposure to credit risk such risk associated with foreign currency because their counterparties may be similarly exchange variations related to Canadian- affected by economic or regulatory changes or denominated purchase and swap agreements. other changes in conditions.

PG&E Corporation is also exposed to foreign currency risk resulting from the need to translate PG&E Corporation and the Utility manage their Canadian-denominated financial statements of an credit risk in accordance with their respective affiliate into U.S. dollars in the PG&E Risk Management Policies. The policies establish Corporation Consolidated Financial Statements. processes for assigning credit limits to PG&E Corporation and the Utility use forwards, counterparties before entering into agreements swaps, and options to hedge foreign currency with significant exposure to PG&E Corporation exposure. and the Utility. These processes include an evaluation of a potential counterparty's financial For the Utility, changes in gas purchase costs condition, net worth, credit rating, and other due to fluctuations in the value of the Canadian credit criteria as deemed appropriate, and are dollar would be passed through to customers in performed at least annually.

rates, as long as the overall costs of purchasing gas are within a 99 percent to 102 percent Credit exposure is calculated daily, and in the tolerance band of the benchmark price under the event that exposure exceeds the established CPIM mechanism, as discussed above. The limits, PG&E Corporation and the Utility take Utility's customers and shareholders would share immediate action to reduce the exposure, or in the costs or savings outside of the tolerance obtain additional collateral, or both. Further, band equally. PG&E Corporation and the Utility rely heavily on master agreements that require the counterparty PG&E Corporation and the Utility use sensitivity to post security, referred to as credit collateral, in analysis to measure their exchange rate exposure the form of cash, letters of credit, corporate to the Canadian dollar. Based on a sensitivity guarantees of acceptable credit quality, or analysis at December 31, 2002, a 10 percent eligible securities if current net receivables and devaluation of the Canadian dollar would be replacement Lost exposure exceed contractually immaterial to PG&E Corporation's and the specified limits.

Utility's Consolidated Financial Statements.

PG&E Corporation and the Utility calculate gross Credit Risk credit exposure for each counterparty as the current mark-to-market value of the contract Credit risk is the risk of loss that PG&E (that is, the amount that would be lost if the Corporation and the Utility would incur if counterparty defaulted today) plus or minus any counterparties failed to perform their contractual outstanding net receivables or payables, prior to obligations (these obligations are reflected as the application of the counterparty's credit Accounts Receivable - Customers, net; notes collateral.

receivable included in Other Noncurrent Assets -

Other; Price Risk Management (PRM) assets; and In 2002, PG&E Corporation's and the Utility's Assets held for sale on the balance sheet). PG&E credit risk increased due in part to downgrades Corporation and the Utility conduct business of some counterparties credit ratings to levels primarily with customers or vendors, referred to below investment grade. The downgrades as counterparties, in the energy industry. These increase PG&E Corporation's or the Utility's counterparties include other investor-owned credit risk because any collateral provided by utilities, municipal utilities, energy trading these counterparties in the form of corporate companies, financial institutions, and oil and gas guarantees or eligible securities may be of lesser production companies located in the United or no value. Therefore, in the event these States and Canada. This concentration of counterparties failed to perform under their counterparties may impact PG&E Corporation's contracts, PG&E Corporation and the Utility may 65

face a greater potential maximum loss. In 10 percent of PG&E Corporation's net credit contrast, PG&E Corporation and the Utility do exposure. At December 31, 2002, the Utility had not face any additional risk if counterparties' one investment grade counterparty that credit collateral is in the form of cash or letters represented 21 percent of the Utility's net credit of credit, as this collateral is not affected by a exposure, and one below investment grade credit rating downgrade. counterparty that represented 11 percent of the Utility's net credit exposure. At December 31, For the year ended December 31, 2002, PG&E 2001, the Utility had no single counterparty that Corporation and the Utility have recognized no represented greater than 10 percent of the losses due to the contract defaults or Utility's net credit exposure.

bankruptcies of counterparties. However, in 2001, PG&E Corporation terminated its contracts The schedule below summarizes PG&E with a bankrupt company, which resulted in a Corporation's and the Utility's credit risk pre-tax charge to earnings of $60 million related exposure to counterparties that are in a net asset to trading and non-trading activities, after position, with the exception of exchange-traded application of collateral held and accounts futures (the exchange provides for contract payable. settlement on a daily basis), as well as PG&E Corporation's and the Utility's credit risk At December 31, 2002, and at December 31, exposure to counterparties with a greater than 2001, PG&E Corporation had no single 10 percent net credit exposure, at December 31, counterparty that represented greater than 2002, and December 31, 2001:

Gross Credit Number of Net Exposure of Exposure Before Cro dit Net Credit Counterparties Counterparties (in milons) Credit coIaterAl") Cottau .xaf2) Exposure'l) >10% >100%

At December 31, 2002 PG&E Corporation .......... $ 1,165 $ 195 $ 970 Utility t3) ................. 288 113 175 2 55 At December 31, 2001 PG&E Corporation .......... $ 1,203 $ 207 $ 996 _ $

Utility ' ................. 271 127 144

.t' Gross credit exposure equals mark-to-market value (adjusted for applicable credit valuation adjustments), notes receivable, and net (payables) receivables where netting is allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value, liquidity, or model.

(2 Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit).

"' The Utility's gross credit exposure indudes wholesale activity only. Retail activity and payables incurred prior to the Utility's bankruptcy filing are not included. Retail activity at the Utility consists of the accounts receivable from the sale of gas and electricity to millions of residential and small commercial customers.

At December 31, 2002, approximately Utility's net credit exposure was to entities that

$205 million, or 21 percent of PG&E had credit ratings below investment grade.

Corporation's net credit exposure was to entities Investment grade is determined using publicly that had credit ratings below investment grade. available information, i.e., rated at least Baa3 by At December 31, 2002, approximately Moody's and BBI3- by S&P. If the counterparty

$64 million, or 37 percent of the Utility's net provides a guarantee by a higher rated entity credit exposure was to entities that had credit (e.g., its parent), the credit rating determination ratings below investment grade. At December 31, is based on the rating of its guarantor.

2001, approximately $244 million, or 25 percent of PG&E Corporation's net credit exposure was At December 31, 2002, approximately to entities that had credit ratings below $65 million, or 7 percent of PG&E Corporation's investment grade. At December 31, 2001, net credit exposure was with counterparties at approximately $32 million, or 22 percent of the PG&E NEG that are not rated. At December 31, 66

2001, none of PG&E Corporation's net credit as amended by SFAS No. 138, "Accounting for exposure was with counterparties at PG&E NEG Certain Derivative Instruments and Hedging that were not rated. Most counterparties with no Activities" (collectively, SPAS No. 133), which credit rating are governmental authorities which required all derivative instruments to be are not rated, but which PG&E Corporation has recognized in the financial statements at their fair assessed as equivalent to investment grade. value. Prior to its rescission, PG&E Corporation Other counterparties with no credit rating are accounted for its energy trading activities in subject to an internal assessment of their credit accordance with Emerging Issues Task Force quality and a credit rating designation. (EITF) No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk PG&E Corporation has regional concentrations of Management Activities", and SPAS No. 133, credit exposure to counterparties that conduct which require certain energy trading contracts to business primarily in the western United States be accounted for at fair values using and also to counterparties that conduct business mark-to-market accounting. See discussion of primarily throughout North America. The Utility Rescission of EITF 98-10 below.

has a regional concentration of credit risk associated with its receivables from residential Effective for the third quarter ended and small commercial customers in northern September 30, 2002, PG&E Corporation adopted California. However, the risk of material loss due the net method of recognizing realized gains and to nonperformance from these customers is not losses on energy trading contracts. Under the net considered likely. Reserves for uncollectible method, revenues and expenses are netted and accounts receivable are provided for the trading gains (or losses) are reflected in revenues potential loss from nonpayment by these on the income statement, as opposed to customers based on historical experience. The reporting revenues and expenses under the Utility has a net regional concentration of credit previously used gross method.

exposure totaling $175 million to counterparties that conduct business primarily throughout North PG&E Corporation and the Utility have derivative America. commodity contracts for the physical delivery of purchase and sale quantities such as natural gas CRITICAL ACCOUNTING POLICIES and power transacted in the normal course of business. These derivatives are exempt from the The preparation of Consolidated Financial requirements of SFAS No. 133 under the normal Statements in accordance with accounting purchases and sales exception, and are not principles generally accepted in the United States reflected on the balance sheet at fair value. See involves the use of estimates and assumptions further discussion in Notes 1 and 11 of the Notes that affect the recorded amounts of assets and to the Consolidated Financial Statements.

liabilities as of the date of the financial statements and the reported amounts of revenues PG&E Corporation and the Utility apply SFAS and expenses during the reporting period. No. 71, "Accounting for the Effects of Certain Certain of these estimates and assumptions are Types of Regulation," to their regulated considered to be Critical Accounting Policies, operations. Under SFAS No. 71, regulatory assets due to their complexity, subjectivity, and represent capitalized costs that would otherwise uncertainty, along with their relevance to the be charged to expense. These costs are later financial performance of PG&E Corporation. recovered through regulated rates. Regulatory Actual results may differ substantially from these liabilities are rate actions of a regulator that will estimates. These policies and their key later be credited to customers through the rate characteristics are outlined below. making process. Regulatory assets and liabilities are recorded when it is probable that these items In 2001, PG&E Corporation and the Utility will be recovered or reflected in future rates. If it adopted SFAS No. 133, "Accounting for is determined that these items are no longer Derivative Instruments and Hedging Activities," probable of recovery under SPAS No. 71, then 67

they will be written-off at that time. At financially able to contribute to these costs, December 31, 2002, PG&E Corporation reported (2) the extent of contamination or necessary regulatory assets of $2.2 billion, including current remediation is greater than anticipated, or (3) the regulatory balancing accounts receivable and Utility is found to be responsible for clean-up regulatory liabilities of $1.8 billion, including costs at additional sites.

current regulatory balancing accounts payable.

See Note 1 of the Notes to the Consolidated The process of estimating remediation liabilities Financial Statements. is difficult and changes in the estimate could occur given the uncertainty concerning the The Utility records revenues as electricity and Utility's ultimate liability, the complexity of natural gas are delivered. A portion of the environmental laws and regulations, the selection revenue recognized has not yet been billed. of compliance alternatives, and the financial Unbilled revenues are determined by factoring ability of other responsible parties. PG&E NEG the actual load (energy) delivered with recent estimates that it may be required to spend up to historical usage and rate patterns. approximately $608 million before insurance proceeds for environmental compliance at Due to the Utility's filing for bankruptcy in 2001, certain of its operating facilities. To date, PG&E the financial statements for both PG&E NEG has spent approximately $13 million on Corporation and the Utility are prepared in environmental compliance. See Note 16 of the accordance with SOP 90-7, which is used by Notes to the Consolidated Financial Statements.

reorganizing entities operating under the Bankruptcy Code. Under SOP 90-7, certain Since the CPUC authorized the collection of claims against the Utility prior to its bankruptcy incremental surcharge revenues in January and filing are recorded as Liabilities Subject to March 2001, the Utility has used generation-Compromise. The Utility reported a total of related revenues in excess of generation-related

$9.4 billion of Liabilities Subject to Compromise costs to recover approximately $1.9 billion (after-at December 31, 2002. While the Utility operates tax) in previously written-off under collected under the protection of the Bankruptcy Court, purchased power and generation-related charges.

the realization of assets and the liquidation of For the 12 months ended December 31, 2002, liabilities is subject to uncertainty, as additional total surcharge revenues recognized were claims to Liabilities Subject to Compromise can $1.8 billion (after-tax). For the 12 months ended change due to such actions as the resolution of December 31, 2001, total surcharge revenues disputed claims or certain Bankruptcy Court recognized were $1.3 billion (after-tax). The actions. See Note 2 of the Notes to the Utility has not provided reserves for potential Consolidated Financial Statements. refunds of these surcharges as it believes that recent regulatory orders and actions provide The Utility records an environmental remediation evidence that it is not probable that a refund will liability when site assessments indicate that be ordered. However, it is possible that remediation is probable and the cost can be subsequent decisions by the CPUC may affect reasonably estimated. This liability is based on the amount and timing of these surcharge site investigations, remediation, operations, revenues recovered by the Utility and that maintenance, monitoring, and closure. This subsequent CPUC decisions may order the Utility liability is reviewed on a quarterly basis, and is to refund all or a portion of the surcharge recorded at the lower range of estimated costs, revenues collected. See Note 2 of the Notes to unless there is a better estimate available. At the Consolidated Financial Statements and risk December 31, 2002, the Utility's undiscounted factors discussed in the Overview section of this environmental remediation liability was MD&A for further discussion. See Note 1 of the

$331 million. The Utility's future cost could Notes to the Consolidated Financial Statements increase to as much as $444 million if (1) the for further discussion of accounting policies and other potentially responsible parties are not new accounting developments.

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ACCOUNTING PRONOUNCEMENTS ISSUED Certain new and expanded disclosure BUT NOT YET ADOPrED requirements apply to all financial statements issued afterJanuary 31, 2003, regardless of when Consolidation of Variable Interest the variable interest entity was established. These Entities - In January 2003 the Financial disclosures are required if there is an assessment Accounting Standards Board (FASB) issued that it is reasonably possible that an enterprise Interpretation No. 46, "Consolidation of Variable will consolidate or disclose information about a Interest Entities" (FIN 46), which expands upon variable interest entity when FIN 46 becomes existing accounting guidance addressing when a effective. PG&E Corporation is currently company should include in its financial evaluating the impacts of FIN 46's initial statements the assets, liabilities, and activities of recognition, measurement, and disclosure another entity. FIN 46 notes that many of what provisions on its Consolidated Financial are now referred to as "variable interest entities" Statements.

have commonly been referred to as special-purpose entities or off-balance sheet structures. Guarantor'sAccounting and Disclosure However, the Interpretation's guidance is to be Requirements for Guarantees- In applied to not only these entities but to all November 2002, the FASB issued Interpretation entities found within a company. FIN 46 No. 45, "Guarantor's Accounting and Disclosure provides some general guidance as to the Requirements for Guarantees, Including Indirect definition of a variable interest entity. PG&E Guarantees of Indebtedness of Others" (FIN 45).

Corporation is currently evaluating all entities to FIN 45 expands on the accounting guidance of determine if they meet the FIN 46 criteria as SPAS No. 5, "Accounting for Contingencies,"

variable interest entities. SPAS No. 57, "Related Party Disclosures," and SFAS No. 107, "Disclosures about Fair Value of Until the issuance of FIN 46, one company Financial Instruments." FIN 45 also incorporates, generally included another entity in its without change, the provisions of FASB Consolidated Financial Statements only if it Interpretation No. 34, "Disclosures of Indirect controlled the entity through voting interests. Guarantees of the Indebtedness of Others,"

FIN 46 changes that by requiring a variable which it supersedes.

interest entity to be consolidated by a company if that company is subject to a majority of the FIN 45 elaborates on the existing disclosure risk of loss from the variable interest entity's requirements for most guarantees. It clarifies that activities or entitled to receive a majority of the a guarantor's required disclosures include the entity's residual returns, or both. A company that nature of the guarantee, the maximum potential consolidates a variable interest entity is now undiscounted payments that could be required, referred to as the "primary beneficiary" of that the current carrying amount of the liability, if entity. any, for the guarantor's obligations (including the liability recognized under SFAS No. 5), and the FIN 46 requires disclosure of variable interest nature of any recourse provisions or available entities that the company is not required to collateral that would enable the guarantor to consolidate but in which it has a significant recover amounts paid under the guarantee.

variable interest.

FIN 45 also clarifies that at the time a company The consolidation requirements of FIN 46 apply issues a guarantee, it must recognize an initial immediately to variable interest entities created liability for the fair value of the obligation it after January 31, 2003. The consolidation assumes under that guarantee, including its requirements apply to variable interest entities ongoing obligation to stand ready to perform created before January 31, 2003, in the first fiscal over the term of the guarantee in the event that year or interim period beginning after June 15, specified triggering events or conditions occur.

2003, so these requirements would be applicable This information must also be disclosed in to PG&E Corporation in the third quarter 2003. interim and annual financial statements.

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FIN 45 does not prescribe a specific account for existence at or prior to October 25, 2002, the the guarantor's offsetting entry when it estimated impact of the first quarter 2003 recognizes the liability at the inception of the cumulative effect of a change in accounting guarantee, noting that the offsetting entry would principle is a loss of $5 million, net of taxes at depend on the circumstances in which the December 31, 2002.

guarantee was issued. There also is no prescribed approach included for subsequently Accountingfor Costs Associated wutb Exit measuring the guarantor's recognized liability or DisposalActivities - In June 2002, the over the term of the related guarantee. It is FASB issued SFAS No. 146, "Accounting for Costs noted that the liability would typically be Associated with Exit or Disposal Activities,"

reduced by a credit to earnings as the guarantor which addresses accounting for restructuring and is released from risk under the guarantee. similar costs. SPAS No. 146 supersedes previous -

accounting guidance, principally EITF Issue The initial recognition and initial measurement No. 94-3, "Liability Recognition for Certain provisions apply on a prospective basis to Employee Termination Benefits and Other Costs guarantees issued or modified after to Exit an Activity" (EITF 94-3). PG&E December 31, 2002. PG&E Corporation is Corporation will adopt the provisions of SFAS currently evaluating the impact of FIN 45's initial No. 146 for restructuring activities initiated after recognition and measurement provisions on its December 31, 2002. SPAS No. 146 requires that Consolidated Financial Statements. The the liability for costs associated with an exit or disclosure requirements for FIN 45 are effective disposal activity be recognized when the liability for financial statements of interim or annual is incurred. Under EITF 94-3, a liability for an periods ending after December 15, 2002, and exit cost was recognized at the date of the have been incorporated into PG&E Corporation's company's commitment to an exit plan if certain December 31, 2002, disclosures of guarantees. other criteria were met. SPAS No. 146 also establishes that the liability initially should be Rescission of EJF98 In October 2002, measured and recorded at fair value.

the Emerging Issues Task Force rescinded Accordingly, the prospective implementation of EITF 98-10. Energy trading contracts that are SPAS No. 146 may affect the timing of derivatives in accordance with SFAS No. 133 will recognizing future restructuring costs as well as continue to be accounted for at fair value under the amounts recognized.

SFAS No. 133. Contracts that were previously marked to market as trading activities under Accountingfor Asset Retirement EITF 98-10 that do not meet the definition of a Obligations- In June 2001, the FASB issued derivative will be recorded at cost, with a SFAS No. 143, "Accounting for Asset Retirement one-time adjustment to be recorded as a Obligations." PG&E Corporation and the Utility cumulative effect of a change in accounting will adopt this Statement effective January 1, principle as of January 1, 2003. For PG&E 2003. SPAS No. 143 provides accounting Corporation, the majority of trading contracts are requirements for costs associated with legal derivative instruments as defined in SFAS obligations to retire tangible, long-lived assets.

No. 133. The rescission of EITF 98-10 has no Under the Statement, the asset retirement effect on the accounting for derivative obligation is recorded at fair value in the period instruments used for non-trading purposes, in which it is incurred by increasing the carrying which continue to be accounted for in amount of the related long-lived asset. In each accordance with SFAS No. 133. subsequent period, the liability is accreted to its present value and the capitalized cost is The reporting requirements associated with the depreciated over the useful life of the related rescission of EITE 98-10 are to be applied asset. Upon adoption, the cumulative effect of prospectively for all EITF 98-10 energy trading applying this Statement will be recognized as a contracts entered into after October 25, 2002. For change in accounting principle in the all EITF 98-10 energy trading contracts in Consolidated Statements of Operations. However, 70

rate-regulated entities may recognize regulatory

• PG&E NEG estimates that it will recognize assets or liabilities as a result of timing a liability in the range of $11 million to differences between the recognition of costs as $21 million for asset retirement obligations recorded in accordance with this statement and on January 1, 2003. The cumulative effect costs recovered through the ratemaking process. of a change in accounting principle from Regulatory assets and liabilities may be recorded unrecognized accretion and depreciation when it is probable that the asset retirement expense is estimated to be a loss in the costs will be recovered through the ratemaking range of $4 million to $6 million (pre-tax).

process.

PENSION AND OTHER POST-RETIREMENT PG&E Corporation estimates the impact of PIANS adopting SFAS No. 143 effective January 1, 2003 will be as follows: PG&E Corporation and its subsidiaries provide The Utility will adjust its nuclear qualified and non-qualified non-contributory defined benefit pension plans for their decommissioning obligation to reflect the employees, retirees, and non-employee directors.

fair value of decommissioning its nuclear PG&E Corporation and its subsidiaries also power facilities. The Utility will also provide contributory defined benefit medical recognize asset retirement obligations plans for certain retired employees and their associated with the decommissioning of eligible dependents, and noncontributory defined other fossil generation assets.

benefit life insurance plans for certain retired At December 31, 2002, the total nuclear employees (referred to collectively as other decommissioning obligation accrued was benefits). Amounts that PG&E Corporation and

$1.3 billion and is included in the Utility recognize as obligations to provide accumulated depreciation and pension benefits under SFAS No. 87, "Employers' decommissioning on the Consolidated Accounting for Pensions," and other benefits Balance Sheets (see Note 13, "Nuclear under SFAS No. 106. "Employers Accounting for Decommissioning"). The Utility had Postretirement Benefits other than Pensions" are accrued, at December 31, 2002, based on certain actuarial assumptions. Actuarial

$52 million to decommission certain fossil assumptions used in determining pension generation assets based on its estimate of obligations include the discount rate, the average the decommissioning obligation under the rate of future compensation increases, and the accounting principles in effect at that expected return on plan assets. Actuarial time. These decommissioning obligations assumptions used in determining other benefit are also included in accumulated obligations include the discount rate, the average depreciation and decommissioning on the rate of future compensation increases, the Consolidated Balance Sheets. expected return on plan assets, and the assumed health care cost trend rate. While PG&E The Utility estimates it will recognize an Corporation and the Utility believe the adjustment to its recorded nuclear and assumptions used are appropriate, significant fossil facility decommissioning obligations differences in actual experience, plan changes, in the range of an increase of $222 million to a decrease of $192 million for asset or significant changes in assumptions may materially affect the recorded pension and other retirement obligations in existence as of benefit obligations and future plan expenses.

January 1, 2003. The estimated cumulative effect of a change in accounting principle Pension and other benefit funds are held in from unrecognized accretion expense and external trust funds. Trust assets, including adjustments to depreciation and accumulated earnings, must be used exclusively decommissioning expense accrued to date for pension and other benefit payments.

will range from a loss of $19 million to a Consistent with the trusts' investment policies, gain of $17 million (pre-tax).

assets are invested in U.S. equities, non-U.S.

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equities, and fixed income securities. Investment and currently is discussing these adjustments securities are exposed to various risks, such as with the IRS' Appeals Office. The IRS also is interest rate, credit, and overall market volatility auditing PG&E Corporation's 1999 and 2000 risks. As a result of these risks, it is reasonably consolidated U.S. federal income tax returns, but possible that the market values of investment has not issued its final report. However, the IRS securities could increase or decrease in the near has proposed adjustments totaling $77 million term. Increases or decreases in market values (including interest). The resolution of these could materially affect the current value of the matters with the IRS is not expected to have a trusts and, as a result, the future level of pension material adverse effect on PG&E Corporation's and other benefit expense. earnings. All of PG&E Corporation's federal income tax returns prior to 1997 have been Expected rates of return on plan assets were closed. In addition, California and certain other developed by determining projected stock and state tax authorities currently are auditing various bond returns and then applying these returns to state tax returns. The results of these audits are the target asset allocations of the employee not expected to have a material adverse effect benefit trusts, resulting in a weighted average on PG&E Corporation's earnings. In the third rate of return on plan assets. Fixed income quarter of 2002, PG&E Corporation re-evaluated returns were based on historic returns for the its position with respect to the expected broad U.S. bond market. Equity returns were realization of certain synthetic fuel tax credits, determined by applying a market risk premium and as a result, recorded additional tax benefits of 3.5 percent to the U.S. bond market return. totaling $43 million.

For the Utility Retirement Plan, the assumed return of 8.1 percent compares to a ten-year Deferred tax assets with respect to impairments actual return of 8.4 percent. and write-offs at PG&E NEG were recorded in 2002. Due to uncertainty in realizing state tax The rate used to discount pension and other benefits associated with these deferred tax assets, post-retirement benefit plan liabilities was based valuation allowances were established.

on a yield curve developed from the Moody's AA Corporate Bond Index at December 31, 2002. A valuation allowance of $97 million associated This yield curve has discount rates that vary with state tax benefits was recorded in based on the maturity of the obligations. The continuing operations. In addition, a valuation estimated future cash flows for the pension and allowance of $87 million associated with state other post retirement obligations were matched tax benefits was recorded in discontinued to the corresponding rates on the yield curve to operations.

derive a weighted average discount rate. The resulting rate was validated by comparison to the ENVIRONMENTAL AND LEGAL MATIERS yield of a high-quality, non-callable corporate bond portfolio with cash flows corresponding to PG&E Corporation and the Utility are subject to expected future benefit payments. For the Utility laws and regulations established both to maintain Retirement Plan, a 25 basis point decrease in the and to improve the quality of the environment.

discount rate would increase the accumulated Where PG&E Corporation's and the Utility's benefit obligation by approximately $240 million.

properties contain hazardous substance, these laws and regulations require PG&E Corporation TAXATION MAT1EBS and the Utility to remove those substances or to The Internal Revenue Service (IRS) has remedy effects on the environment. Also, in the completed its audit of PG&E Corporation's 1997 normal course of business, PG&E Corporation and 1998 consolidated U.S. federal income tax and the Utility are named as parties in a number returns and has assessed additional federal of claims and lawsuits. See Note 16 of the Notes income taxes of $70 million (including interest). to the Consolidated Financial Statements for PG&E Corporation has filed protests contesting further discussion of environmental matters and certain adjustments made by the IRS in that audit significant pending legal matters.

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PG&E Corporation CONSOUIATED STI&TEMENTS OF OPERATIONS (in millions, except per share amounts) Year ended December 31, 2002 2001 2000 Operating Revenues Utility .................................................. $10,514 $10,462 $ 9,637 Energy commodities and services ................................. 1,981 1,748 2,931 Total operating revenues ................................... 12,495 12,210 12,568 Operating Expenses Cost of electricity and natural gas for utility .......................... 2,436 4,606 8,166 Deferred electric procurement cost ................................ - (6,465)

Cost of energy commodities and services ............................ 1,323 1,047 1,990 Depreciation, amortization, and decommissioning ...................... 1,309 1,002 3,595 Operating and maintenance. .................................... 3,373 2,867 3,272 Impairments, write-offs, and other charges ........................... 2,767 Provision for loss on generation-related regulatory assets and under-collected purchased power costs ...................................... - 6.939 Reorganization professional fees and expenses ........................ 155 97 -

Total operating expenses ................................... 11,363 9,619 17,497 Operating Income (Loss) ...................................... 1,132 2,591 (4,929)

Reorganization interest income ................................ 71 91 -

Interest income ............................................. 61 76 214 Interest expense ............................................ (1,454) (1,209) (788)

Other income (expense), net .................................... 90 (31) (23)

Income (Loss) Before Income Taxes .............................. (100) 1,518 (5,526)

Income tax provision (benefit) ................................... (43) 535 (2,103)

Income (Loss) from Continuing Operations ........................ (57) 983 (3,423)

Discontinued Operations Earnings from operations of USGenNE, Mountain View, and ET Canada (net of income taxes of $3 million in 2002, $73 million in 2001, and $75 million in 2000) .................................................. 11 107 99 Loss on disposal of USGenNE and ET Canada (net of income taxes of

$381 million) ............................................. (767)

Loss on disposal of PG&E Energy Services (net of income taxes of $36 million) (40)

Net Income (Loss) Before Cumulative Effect of Changes in Accounting Principles ................................................ (813) 1,090 (3,364)

Cumulative effect of changes in accounting principles (net of income taxes of $42 million in 2002 and $6 million in 2001) ........................... (61) 9 Net Income (Loss) .......................................... $ (874) $ 1,099 $ (3,364)

Weighted Average Common Shares Outstanding, Basic ................. 371 363 362 Earnings (Loss) Per Common Share, from Continuing Operations, Basic ... $ (0.15) $ 2.71 $ (9.45)

Net Earnings (loss) Per Common Share, Basic ...................... $ (2.36) $ 3.03 $ (9.29)

Earnings (Loss) Per Common Share, from Continuing Operations, Diluted . . $ (0.15) $ 2.70 $ (9.45)

Net Earnings (Loss) Per Common Share, Diluted ..................... $ (2.36) $ 3.02 $ (9.29)

Dividends Declared Per Common Share ...........................

$ $ 1.20 See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation CONSOLEDATED BALANCE SHEETS ------ I (in Millions) Balance at December 31, 2002 2001 ASSETS Current Assets Cash and cash equivalents ....................................... $ 3,895 $ 5,355 Restricted cash ............................................... 708 195 Accounts receivable:

Customers (net of allowance for doubtful accounts of $113 million and

$89 million, respectively) ..................................... 2,747 2,750 Regulatory balancing accounts ................................ 98 75 Price risk management .......................................... 498 240 Inventories .................................................. 347 383 Assets held for sale ............................................ 707 744 Prepaid expenses and other ................ . . .. 480 135 Total current assets ................... . . .. 9,480 9,877 Property, Plant and Equipment Utility ............................... . . .. 27,045 25,963 Non-utility:

Electric generation .....................

636 961 Gas transmission ...................... .. . .. . .. . ........... 1,761 1,514 Construction work in progress ............... .. . .. . .. . ........... 1,560 2,383 Other ............................... .. . .. . .. . ........... 177 195 Total property, plant and equipment ...... 31,179 31,016 Accumulated depreciation and decommissioning (14,251) (13,615)

Net property, plant and equipment ....... 16,928 17,401 Other Noncurrent Assets Regulatory assets...................... 2,053 2.319 Nuclear decommissioning funds ............. 1,335 1,337 Price risk management .................... 398 363 Deferred income taxes .................... ........... .. . .. . .. . . 657 Assets held for sale ...................... ........... .. . .. . .. . . 916 2,254 Other ............................... ........... .. . .. . .. . . 1,929 2,412 Total other noncurrent assets ........... 7,288 8,685 TOTAL ASSETS.......................... $ 33,6% $ 35,963 See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation CONSOLUDATED BALANCE SHEETS (in millions, except share amounts) Balance at December 31, 2002 2001 LIABInInIES AND STOCKHOIDERS' EQUITY Liabilities Not Subject to Compromise Current Liabilities Short-term borrowings ................ .. . .. . . .. . . .. . .. .. . .. . .. $ $ 330 Debt in default ..................... ......................... 4,230 Long-term debt, classified as current ....... ......................... 298 381 Current portion of rate reduction bonds ......................... 290 290 Accounts payable:

Trade creditors ................... ......................... 1,273 1,020 Regulatory balancing accounts ......... ......................... 360 360 Other .......................... ......................... 660 530 Interest payable .................... ......................... 139 26 Income taxes payable ................ ......................... 129 610 Price risk management ................ ......................... 506 152 Liabilities of operations held for sale ...... ......................... 699 570 Other ........................... ......................... 685 696 Total current liabilities ............ 9,269 4,965 Noncurrent liabilities Long-term debt ..................... ...................... 4,345 7,222 Rate reduction bonds ................. ...................... 1,160 1,450 Deferred income taxes ................ ...................... 1,439 1,479 Deferred tax credits .................. ...................... 144 153 Price risk management ................ ............... I ...... 305 385 Liabilities of operations held for sale ...... ...................... 793 1,002 Other ........................... ...................... 2,963 2,999 Total noncurrent liabilities ......... 11,149 14,690 Llabilities Subject to Compromise Financing debt ..................... 5,605 5,651 Trade creditors ..................... 3,580 5,555 Total liabilities subject to compromise. 9,185 11,206 Commitments and Contingencies (Notes 1, 2, 3 and 16) .................

Preferred Stock of Subsidiaries .................................... 480 480 Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures ............................ 300 Common Stockholders' Equity Common stock, no par value, authorized 800,000,000 shares, issued 405,486,015 and 387,898,848 shares, respectively .................................. 6,274 5,986 Common stock held by subsidiary, at cost, 23,815,500 shares ................ (690) (690)

Accumulated deficit ............................................ (1,878) (1,004)

Accumulated other comprehensive income (loss) ........................ (93) 30 Total common stockholders' equity ............................. 3,613 4,322 TOTAL LIABUII[ES AND STOCKHOLDERS' EQUITY ..................... $33,696 $35,963 See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation CONSOLIDATED STATEMENTS OF CASH FLOWS (in mnijlons) Year Ended December 31, 2002 2001 2000 Cash Flows from Operating Activities Net loss (income) ........................................... $ (874) $ 1,099 5(3,364)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, amortization, and decommissioning ...................... 1,309 1,002 3,595 Deferred electric procurement costs ..- (6,465)

Reversal of ISO accrual ..... ....... ....... ......... (970) - -

Deferred income taxes and tax credits, net .......................... (521) (535) (819)

Price risk management assets and liabilities, net ....................... (142) 164 33 Other deferred charges and noncurrent liabilities ....................... 263 (744) 256 Provision for loss on generation-related regulatory assets and under-collected purchased power costs ...................................... - - 6,939 Loss on impairment or disposal of assets ............................ 2,767 - -

Loss from discontinued operations ................................ 1,148 - 40 Cumulative effect of change in accounting principle ..................... 61 (9)

Net effect of changes in operating assets and liabilities:

Restricted cash ............ ...................... (513) (66) (6)

Accounts receivable ......................................... 51 1,000 (1,941)

Inventories .......... .................................... 36 (75) 68 Accounts payable .......................................... 377 1,213 4,200 Accrued taxes ......... ................................... (481) 1,851 (1,452)

Regulatory balancing accounts, net ............................... (23) 311 (410)

Payments authorized by the Bankruptcy Court on amounts classified as liabilities subject to compromises (Note 2) ............................... (1,442) (16)

Assets and liabilities of operations held for sale, net ..................... 34 (117) 64 Other working capital ....................................... (330) (399) 331 Other, net ................................... (216) 602 (314)

Net cash provided by operating activities ............................ 534 5,281 755 Cash Flows from Investing Activities Capital expenditures .......................................... (3,032) (2,773) (2,334)

Net proceeds from sales of businesses ............................... - - 415 Other, net ................................................ 482 (103) 241 Net cash used by Investing activities ............................... (2.550) (2,876) (1,678)

Cash Flows from Financing Activities Net borrowings (repayments) under credit facilities ....................... - (1,148) 2,846 Long-term debt issued ......................................... 2.414 3,008 1,659 Long-term debt matured, redeemed, or repurchased ...................... (1,644) (868) (1,155)

Rate reduction bonds matured .................................... (290) (290)

Common stock issued ......................................... 217 15 65 Common stock repurchased ..................................... - (1) (2)

Dividends paid ............................................. - (109) (436) other, net ................................................ (141) (40) 23 Net cash provided by financing activities ............................ 556 567 3,000 Net change in cash and cash equivalents ............................ (1,460) 2,972 2,077 Cash and cash equivalents at January 1 ............................. 5,355 2,383 306 Cash and cash equivalents at December 31 .......................... $ 3,895 $ 5,355 $ 2,383 Supplemental disclosures of cash flow Information Cash paid for:

Interest (net of amounts capitalized) .............................. $ 1,414 S 579 $ 748 Income taxes paid (refunded), net ................................ 971 (692) 20 Supplemental disclosures of noncash investing and financing activities Retirement of long-term debt on the sale of PG&E Gas Transmission, Texas ...... - - 564 Transfer of liabilities and other payables subject to compromise from operating assets and liabilities ....................................... 419 11,400 See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation CONSOLIDATED STATEMENTS OF COMMON STOCKHOIDERS' EQUrlY Accumulated Common Reinvested Other Total Stock Earnings Comprehensive Common Comprehensive (in millions, except share Common Held by (Accumulated Income Stockholders' Income amounts) Stock Subsidiary Deficit) (LOSS) Equity (Loss)

Balance at December 31, 1999 . $5,906 $(690) $ 1,674 $ (4) $ 6,886 Net loss ........ ....... - - (3,364) - (3,364) 5(3,364)

Common stock issued (2,847,269 shares) ..... ... 65 - - - 65 Common stock repurchased (59,655 shares) ..... .... (1) - (1) - (2)

Cash dividends declared on common stock ..... ..... - - (434) - (434)

Other ................. I - 20 - 21 Balance at December 31, 2000 . 5,971 (690) (2,105) (4) 3,172 Net income ....... ...... - - 1,099 - 1,099 $ 1,099 Cumulative effect of adoption of SFAS No. 133 and interpretations .......... - - - (243) (243) (243)

Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 ....... ....... - 237 237 237 Net reclassification to earnings - - - 42 42 42 Foreign currency translation adjustment ...... ...... - - - (1) (1) (1)

Other ................. - - - (1) (1) (1)

Comprehensive income $ 1,133 Common stock issued (739,158 shares) ....... 1.......

6 - - - 16 Common stock repurchased (34,037 shares) ..... .... (1) - - - (1)

Other ................. - - 2 - 2 Balance at December 31, 2001 . 5,986 (690) (1,004) 30 4,322 Net loss ........ ....... - - (874) - (874) $ (874)

Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 ....... ....... - (139) (139) (139)

Net reclassification to earnings - - - 13 13 13 Foreign currency translation adjustment ...... ...... - - - 2 2 2 Other ................. - - - I 1 I Comprehensive income $ (997)

Common stock issued (17,582,636 shares) .... ... 217 - - - 217 Other ................. 71 - - - 71 Balance at December 31, 2002 . $6,274 $(690) $(1,878) $ (93) S 3,613 See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Company, a Debtor-in-Possession CONSOLIDATED STATEMENTS OF OPERATIONS (In millons) Year Ended December 31, 2002 2001 2000 Operating Revenues Electric . .............................................. $ 8,178 $ 7,326 $ 6,854 Natural gas ............ ............................... 2,336 3,136 2,783 Total operating revenues .............................. 10,514 10,462 9,637 Operating Expenses Cost of electricity .......... ............................. 1,482 2,774 6,741 Deferred electric procurement cost .......................... - - (6,465)

Cost of natural gas ......... ............................. 954 1,832 1,425 Operating and maintenance ............................... 2,817 2,385 2,687 Depreciation, amortization, and decommissioning .... ............ 1,193 896 3,511 Provision for loss on generation-related regulatory assets and under-collected purchased power costs .......................... - - 6,939 Reorganization professional fees and expenses ..... ............. 155 97 Total operating expenses .............................. 6,601 7,984 14,838 Operating Income (Loss) ................................. 3,913 2,478 (5,201)

Reorganization interest income ............................. 71 91 Interest income .......... .............................. 3 32 186 Interest expense (non-contractual interest of $149 million for 2002 and

$164 million for 2001) ........ .......................... (988) (974) (619)

Other income (expense), net ............................... (2) (16) (3)

Income (Loss) Before Income Taxes ......................... 2,997 1,611 (5,637)

Income tax provision (benefit) ............................. 1,178 596 (2,154)

Net Income (Loss) ....................................... 1,819 1,015 (3,483)

Preferred dividend requirement .................. I .......... 25 25 25 Income (Loss) Available for (Allocated to) Common Stock .... ... $ 1,794 $ 990 $(3,508)

See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Comqpany, a Debtor-in-Possession CONSOlIDATED BAIANCE SHEErS (in milions) Balance at December 31, 2002 2001 ASSETS Current Assets Cash and cash equivalents .......................................... $ 3,343 $ 4,341 Restricted cash .................................................. 150 53 Accounts receivable:

Customers (net of allowance for doubtful accounts of $59 million and $48 million, respectively) ................................................ 1,900 2,063 Related parties ................................................ 17 18 Regulatory balancing accounts ....................................... 98 75 Inventories:

Gas stored underground and fuel oil ................................... 154 218 Materials and supplies ............................................ 121 119 Income taxes receivable ............................................ 50 -

Prepaid expenses ................................................ 110 80 Deferred income taxes ............................................. 5 -

Total current assets ............................................... 5,948 6,967 Property, Plant and Equipment Electric ........... ........................................... 18,922 18,153 Gas .......................................................... 8,123 7,810 Construction work in progress ........................................ 427 323 Total property, plant and equipment (at original cost) .................... 27,472 26,286 Accumulated depreciation and decommissioning ............................. (13,515) (12,929)

Net property, plant and equipment ................................. 13,957 13,357 Other Noncurrent Assets Regulatory assets ................................................. 2,011 2,283 Nuclear decommissioning funds ....................................... 1,335 1,337 Other ........... ............................................ 1,300 1,325 Total other noncurrent assets ..................................... 4,646 4,945 TOTAL ASSETS .................................................. $ 24,551 $ 25,269 See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Company, a Debtor-in-Possession CONSOUDAIED BAIANCE SHEETS (in millions, except share amounts) Balance at December 31.

2002 2001 UABHJITIES AND STOCKHOLDERS' EQUTlY Liabilities Not Subject to Compromise Current liabilities Long-term debt, classified as current .................................... . 281 $ 333 Current portion of rate reduction bonds ................. .. ............... 290 290 Accounts payable:

Trade creditors ................. ........................... 380 333 Related parties ......................... ....................... 130 86 Regulatory balancing accounts .................... 360 360 Other ...................................................... 374 289 Interest payable .......................... ....................... 126 26 Income taxes payable ....... .................. .................... - 295 Deferred income taxes ....... .................. .................... - 65 Other ............................. .......................... 625 599 Total current liabilities ................................. 2,566 2,676 Noncurrent Liabilities Long-term debt ................................................. 2,739 3,019 Rate reduction bonds .............................................. 1,160 1,450 Regulatory liabilities .............................................. 1,461 1,485 Deferred income taxes ............................................. 1,485 1,028 Deferred tax credits ............................................... 144 153 Other . ...................................................... 1,274 1,239 Total noncurrent liabilities ....................................... 8,263 8,374 Liabilities Subject to Compromise Financing debt .................................................. 5,605 5,651 Trade creditors .................................................. 3,786 5,733 Total liabilities subject to compromise ............................... 9,391 11,384 Commitments and Contingencies (Notes 1, 2, and 16).- -

Preferred Stock With Mandatory Redemption Provisions 6.30% and 6.570, outstanding 5,500,000 shares, due 2002-2009 .................... 137 137 Company Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures 7.90%, 12,000,000 shares, due 2025 ..................................... - 300 Stockholders' Equity Preferred stock without mandatory redemption provisions Nonredeemable, 5% to 6%, outstanding 5,784,825 shares ...................... 145 145 Redeemable, 4.36% to 7.04%, outstanding 5,973,456 shares ..................... 149 149 Common stock, $5 par value, authorized 800,000,000 shares, issued 321,314,760 shares 1,606 1,606 Common stock held by subsidiary, at cost, 19,481,213 shares ........ (475) (475)

Additional paid-in capital .................. ............ ,964 1,964 Reinvested earnings (accumulated deficit) ................................. 805 (989)

Accumulated other comprehensive income (loss) .. ............. -............. (2)

Total stockholders' equity ........................................ 4,194 Z398 TOTAL LLABUIULES AND STOCKHOLDERS' EQUITY .......................... $24,551 $25,269 See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Company, a Debtor-in-Possession CONSOUDATIED STATEMENTS OF CASH FLOWS (in millions) Year Ended December 31, 2002 2001 2000 Cash Flows from Operating Activities Net income (loss) ............................................. $ 1,819 $ 1,015 5(3.483)

Adjustments to reconcile net income (oss) to net cash provided by operating activities:

Deferred electric procurement costs ................................ - - (6,465)

Depreciation, amortization, and decommissioning ........................ 1,193 896 3,511 Deferred income taxes and tax credits, net ............................ 378 (306) (930)

Other deferred charges and noncurrent liabilities ........................ 102 (954) 480 Reversal of ISO accrual (Note 2) .................................. (970) - -

Provision for loss on generation-related regulatory assets and under-collected purchased power costs ....................................... 6,939 Net effect of changes in operating assets and liabilities:

Restricted cash ............................................. (97) (3) (8)

Accounts receivable .......................................... 212 105 (507)

Income tax receivable ......................................... (50) 1,120 (1,120)

Inventories ................................................ 62 (57) 14 Accounts payable.... ........................................ 198 1,312 3,063 Income taxes payable ......................................... (295) 295 (118)

Regulatory balancing accounts, net ................................. (23) 311 (410)

Payments authorized by tde Bankruptcy Court on amounts classified as liabilities subject to compromise (Note 2) ................................. (1,442) (16)

Other working capital ......................................... 11 711 ill Other, net .................................................. 36 336 (522)

Net cash provided by operating activities ............................. 1,134 4,765 555 Cash Flows from Investing Activities Capital expenditures ........................................... (1,546) (1,343) (1,245)

Proceeds from sale of assets ...................................... 11 6 Other, net .................................................. 26 5 32 Net cash used by investing activities ................................ (1,509) (1,338) (1,207)

Cash Flows from Financing Activities Net (repayments) borrowings under credit facilities and short-term borrowings ....... (28) 2,630 Long-term debt issued .......................................... 680 Long-term debt matured, redeemed, or repurchased ........................ (333) (111) (307)

Rate reduction bonds matured ..................................... (290) (290) (290)

Common stock repurchased ...................................... (275)

Dividends paid ........ ..................................... (475)

Other, net .................................................. (1) (26)

Net cash provided (used) by financing activities ........................ (623) (430) 1,937 Net change In cash and cash equivalents ............................. (998) 2,997 1,285 Cash and cash equivalents at January 1 .............................. 4,341 1,344 59 Cash and cash equivalents at December 31 ............................ $ 3,343 S 4,341 $ 1,344 Supplemental disclosures of cash flow Information Cash received for:

Reorganization interest income ................................... $ 75 $ 87 $ -

Cash paid for:

Interest (net of amounts capitalized) ................................ 1,105 361 587 Income taxes (net of refunds) .................................... 1,186 (556)

Reorganization professional fees and expenses ......................... 99 19 Supplemental disclosures of noncash Investing and financing activities Transfer of liabilities and other payables subject to compromise from operating assets and liabilities, net ........................................... 419 11,400 See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Company, a Debtor-in-Possession CONSOLIDATED STATEMENTS OF STOCKHOIDERS' EQUITY Accumu-lated Preferred Reinvested Other Total Stock Addi- Common Earnings Compre- Common Without Compre-tional Stock (Accumu- hensive Stock- hMandatory hensive Common Paid-In Held by lated Income holders' Redemption Income (in millions, except share amounts)) Stock Capital Subsidiary Deficit) (LOss) Equity Provisions (Loss)

Balance December 31, 1999 .... $..1,606 $1,(964 $(200) S 2.107 $ - $ 5,477 $294 Net loss .................... - - - (3,483) - (3,483) - $(3,483)

Common stock repurchased (11,853,448 shares) ........... - (275) _ _ (275)

Cash dividends declared Preferred stock . (25) _ (25)

Common stock .............. (578) _ (578)

Balance December 31, 2000 ...... 1,606 1,964 (475) (1,979) _ 1,116 294 Net Income ................. - - - 1,015 - 1,015 - $ 1,015 Cumulative effect of adoption of SEAS No. 133 .................. _ 90 90 _ 90 Mark-to-market adjustments for hedging .................. _ (5) (5) - (5)

Net reclassification to earnings ...... - (85) (85) - (85)

Foreign currency translation adjustments ................ _ (2) (2) - (2)

Comprehensive income .......... $ 1,013 Preferred stock dividend requirement (25) _ (25)

Balance December 31, 2001 ...... 1,606 1,964 (475) (989) (2) 2,104 294 Net Income ................ - - - 1,819 - 1,819 - $ 1,819 Foreign currency translation adjustments ................ - 2 2 - 2 Comprehensive income .......... $ 1,821 Preferred stock dividend ......... _ _ _ (25) _ (25)

Balance December 31, 2002 ...... $1,606 $1,964 5(475) $ 805 $ - $ 3,900 $294 See accompanying Notes to the Consolidated Financial Statements.

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NOTES TO THE CONSOLIDATED FINANCIAL requires management to make estimates and STATEMENTS assumptions. These estimates and assumptions affect the reported amounts of revenues, NOTE 1: GENERAL expenses, assets, and liabilities and the disclosure of contingencies. As these estimates Organization and Basis of Presentation involve judgments on a wide range of factors, including future economic conditions, that are PG&E Corporation, incorporated in California in difficult to predict, actual results could differ 1995, is an energy-based holding company significantly from these estimates.

headquartered in San Francisco, California. PG&E Corporation conducts its business through Accounting principles used include those various subsidiaries, principally Pacific Gas and necessary for rate-regulated enterprises, which Electric Company (the Utility), an operating reflect the ratemaking policies of the California regulated electric and natural gas distribution and Public Utilities Commission (CPUC) and the transmission utility company, and PG&E National Federal Energy Regulatory Commission (FERC).

Energy Group, Inc. (PG&E NEG), a power generation, wholesale energy marketing and Nature of Operations trading, risk management, and natural gas transmission company. The Utility, incorporated in California in 1905, provides electric service to approximately The Consolidated Financial Statements of PG&E 4.8 million customers and natural gas service to Corporation and of the Utility have been approximately 4.0 million customers in Northern prepared on a going concern basis, which and Central California. Effective January 1, 1997, contemplates continuity of operations, realization PG&E Corporation became the holding company of assets and repayment of liabilities in the of the Utility and its subsidiaries. The Utility is ordinary course of business. However, as a result the predecessor of PG&E Corporation.

of the bankruptcy of the Utility and current liquidity concerns at PG&E NEG and its PG&E NEG, incorporated on December 18, 1998, subsidiaries, as further discussed below, such as a wholly owned subsidiary of PG&E realization of assets and liquidation of liabilities Corporation (shortly thereafter, PG&E are subject to uncertainty. Corporation contributed various subsidiaries to PG&E NEG). The main subsidiaries of PG&E Consoidation Polcy NEG include the following:

• PG&E Generating Company, LLC and its This is a combined annual report of PG&E subsidiaries (collectively, PG&E Gen LLC);

Corporation and the Utility. Therefore, the Notes to the Consolidated Financial Statements apply to

• PG&E Energy Trading Holdings both PG&E Corporation and the Utility. PG&E Corporation and its subsidiaries Corporation's Consolidated Financial Statements (collectively, PG&E Energy Trading or include the accounts of PG&E Corporation, the PG&E ET);

Utility, and PG&E Corporation's wholly owned

• PG&E Gas Transmission Corporation and and controlled subsidiaries. The Utility's its subsidiaries (collectively, PG&E GTC),

Consolidated Financial Statements include its which includes PG&E Gas Transmission, accounts as well as those of its wholly owned Northwest Corporation and its and controlled subsidiaries. All significant inter-subsidiaries, including North Baja company transactions have been eliminated from Pipeline, LLC (NBP) (collectively, PG&E the Consolidated Financial Statements.

GTN).

The preparation of financial statements in PG&E NEG also has other less significant conformity with accounting principles generally subsidiaries.

accepted in the United States of America (GAAP) 83

PG&E National Energy Group, ULC owns reported separately as reorganization items.

100 percent of the stock of PG&E NEG, GTN Finally, the extent to which the Utility's reported Holdings LLC owns 100 percent of the stock of interest expense differs from its stated PG&E GTN, and PG&E Energy Trading Holdings contractual interest is disclosed on the JIC owns 100 percent of the stock of PG&E ET. Consolidated Statements of Operations.

The organizational documents of PG&E NEG and these limited liability companies require PG&E NEG unanimous approval of their respective boards of directors, including at least one independent The Consolidated Financial Statements have been director, before they can: prepared on a going concern basis, which contemplates continuity of operations, realization

• Consolidate or merge with any entity; of assets and repayment of liabilities in the

• Transfer substantially all of their assets to ordinary course of business. However, as a result any entity; or of current liquidity concerns at PG&E NEG and its subsidiaries and restructuring discussions with

• Institute or consent to bankruptcy, their lenders, such realization of assets and insolvency or similar proceedings or liquidation of liabilities are subject to uncertainty.

actions.

As a result of the sustained downturn in the The limited liability companies may not declare power industry, PG&E NEG and its affiliates have or pay dividends unless the respective boards of experienced a financial downturn which caused directors have unanimously approved such the major credit rating agencies to downgrade action, and the company meets specified PG&E NEG's and its affiliates' credit ratings to financial requirements.

below investment-grade. PG&E NEG is currently in default under various recourse debt Bankruptcy of the Utiflty agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, As discussed further in Note 2, on April 6, 2001, other PG&E NEG subsidiaries are in default the Utility filed a voluntary petition for relief under various debt agreements totaling under Chapter 11 of the United States

$2.5 billion, but this debt is non-recourse to Bankruptcy Code (Bankruptcy Code) in the PG&E NEG. PG&E NEG, its subsidiaries and their United States Bankruptcy Court for the Northern lenders are engaged in discussions to restructure District of California (Bankruptcy Court). Under PG&E NEG's and its subsidiaries debt obligations Chapter 11, the Utility continues to control its and other commitments. PG&E NEG and certain assets and is allowed to operate its business as a subsidiaries have significantly reduced their debtor-in-possession while being subject to the energy trading operations. These asset transfers, jurisdiction of the Bankruptcy Court.

sales, and abandonments have caused substantial charges to earnings in 2002 of approximately Due to the Utility's Chapter 11 filing, the

$3.9 billion. PG&E NEG and its subsidiaries are financial statements for both PG&E Corporation continuing these efforts to abandon, sell or and the Utility are prepared in accordance with transfer additional assets in an ongoing effort to the American Institute of Certified Public raise cash, reduce debt, whether through Accountants' Statement of Position (SOP) 90-7, negotiation with lenders or otherwise. As a which is applied by reorganizing entities result, PG&E expects to incur additional operating under the bankruptcy code. Under substantial charges in 2003 as it restructures SOP 90-7, certain liabilities of the Utility existing operations. If a restructuring agreement is not prior to its bankruptcy filing are classified as reached and the lenders exercise their default Liabilities Subject to Compromise. Additionally, remedies or if the financial obligations and professional fees and expenses directly related to commitments are not restructured, PG&E NEG the Chapter 11 proceeding and interest income and certain of its subsidiaries may be compelled on funds accumulated during the bankruptcy are to seek protection under or be forced 84

involuntarily into proceedings under the (In millions, except per Year ended share amounts) December 31, Bankruptcy Code.

2002 2001 2000 Earnings (Loss) Per Sbare Earnings (Loss) Per Common Share, Diluted Income (loss) from Basic earnings (loss) per share is calculated by continuing operations ... $(0.15) $ 2.70 $ (9.45) dividing net income (loss) by the weighted Discontinued operations .. (2.04) 0.29 0.16 average number of common shares outstanding Cumulative effect of change during the period. Diluted earnings (loss) per in accounting principle . . (0.17) 0.02 Rounding ............ 0.01 share is calculated by dividing net income (loss),

adjusted for convertible note interest and Net earnings (loss) ...... $(2.36) $ 3.02 $ (9.29) amortization, by the weighted average number of common shares outstanding plus the assumed The diluted earnings per share for the year issuance of common shares for all dilutive ended December 31, 2002, excludes securities. approximately two million incremental shares related to employee stock options and shares The following table details PG&E Corporation's held by grantor trusts, two million incremental net income (loss) and weighted average common shares related to warrants, and ten million shares outstanding for calculating basic and incremental shares related to the 9.5 percent diluted net income (loss) per share. Convertible Subordinated Notes and includes associated interest expense of $8 million (net of (in millions, except per Year ended share amounts) December 31, income tax of $5 million) due to the antidilutive 2002 2001 2000 effect upon loss from continuing operations. In addition, the diluted share base for the year Income (loss) from continuing operations ........... $ (57) $ 983 $ (3,423) ended December 31, 2000, excludes two million Discontinued operations .... (756) 107 59 incremental shares related to employee stock Net income (loss) before options and shares held by grantor trusts to cumulative effect of secure deferred compensation obligations due to accounting change ...... (813) 1,090 (3,364) the antidilutive effect upon loss from continuing Cumulative effect of operations.

accounting change ...... (61) 9 Net Income (loss) ....... 54(874) S1.099 $ (3,364) PG&E Corporation reflects the preferred Weighted average common dividends of subsidiaries as other expense which shares outstanding, basic 371 363 362 is used to calculate both basic and diluted Add: Employee Stock Options earnings per share.

and PG&E Corporation shares held by grantor trusts .............

Shares outstanding for diluted calculations .... 371 364 362 Earnings (Loss) Per Common Share, Basic Income (loss) from continuing operations ... $(0.15) $ 2.71 $ (9.45)

Discontinued operations. .. (2.04) 0.29 0.16 Cumulative effect of change in accounting principle . (0.17) 0.02 Rounding .......... 0.01 Net earnings (loss) ..... $(2.36) $ 3.03 $ (9.29) 85

Summary of Significant Accounting Policies to PG&E Corporation in the third quarter 2003.

Certain new and expanded disclosure Adoption of New Accounting Policies requirements apply to all financial statements issued afterJanuary 31, 2003, regardless of when Consolidation of Variable interest the variable interest entity was established. These Entities - In January 2003 the Financial disclosures are required if there is an assessment Accounting Standards Board (FASB) issued that it is reasonably possible that an enterprise Interpretation No. 46, "Consolidation of Variable will consolidate or disclose information about a Interest Entities" (FIN 46), which expands upon variable interest entity when FIN 46 becomes existing accounting guidance addressing when a effective. PG&E Corporation is currently company should include in its financial evaluating the impacts of FIN 46's initial statements the assets, liabilities, and activities of recognition, measurement, and disclosure another entity. FIN 46 notes that many of what provisions on its Consolidated Financial are now referred to as "variable interest entities" Statements.

have commonly been referred to as special-purpose entities or off-balance sheet structures. Guarantor'sAccounting and Disclosure However, the Interpretation's guidance is to be Requirementsfor Guarantees- In applied to not only these entities but to all November 2002, the FASB issued Interpretation entities found within a company. FIN 46 No. 45, "Guarantor's Accounting and Disclosure provides some general guidance as to the Requirements for Guarantees, Including Indirect definition of a variable interest entity. PG&E Guarantees of Indebtedness of Others" (FIN 45).

Corporation is currently evaluating all entities to FIN 45 expands on the accounting guidance of determine if they meet the FIN 46 criteria as Statement of Financial Accounting Standards variable interest entities. (SFAS) No. 5, "Accounting for Contingencies,"

SFAS No. 57, "Related Party Disclosures," and Until the issuance of FIN 46, one company SFAS No. 107, "Disclosures about Fair Value of generally included another entity in its Financial Instruments." FIN 45 also incorporates, Consolidated Financial Statements only if it without change, the provisions of FASB controlled the entity through voting interests. FIN Interpretation No. 34, "Disclosures of Indirect 46 changes that by requiring a variable interest Guarantees of the Indebtedness of Others,"

entity to be consolidated by a company if that which it supersedes.

company is subject to a majority of the risk of loss from the variable interest entity's activities or FIN 45 elaborates on the existing disclosure entitled to receive a majority of the entity's requirements for most guarantees. It clarifies that residual returns, or both. A company that a guarantor's required disclosures include the consolidates a variable interest entity is now nature of the guarantee, the maximum potential referred to as the "primary beneficiary" of that undiscounted payments that could be required, entity. the current carrying amount of the liability, if any, for the guarantor's obligations (including the FIN 46 requires disclosure of variable interest liability recognized under SFAS No. 5), and the entities that the company is not required to nature of any recourse provisions or available consolidate but in which it has a significant collateral that would enable the guarantor to variable interest. recover amounts paid under the guarantee.

The consolidation requirements of FIN 46 apply FIN 45 also clarifies that at the time a company immediately to variable interest entities created issues a guarantee, it must recognize an initial after January 31, 2003. The consolidation liability for the fair value of the obligation it requirements apply to variable interest entities assumes under that guarantee, including its created before January 31, 2003, in the first fiscal ongoing obligation to stand ready to perform year or interim period beginning after June 15, over the term of the guarantee in the event that 2003, so these requirements would be applicable specified triggering events or conditions occur.

86

This information must also be disclosed in results. This Statement is effective upon its interim and annual financial statements. issuance.

FIN 45 does not prescribe a specific account for PG&E Corporation continues to account for the guarantor's offsetting entry when it stock-based compensation using the intrinsic recognizes the liability at the inception of the value method in accordance with the provisions guarantee, noting that the offsetting entry would of Accounting Principles Board Opinion (APB) depend on the circumstances in which the No. 25, "Accounting for Stock Issued to guarantee was issued. There also is no Employees," elected under SPAS No. 123, as prescribed approach included for subsequently amended. As a result, the adoption of this measuring the guarantor's recognized liability Statement did not have any impact on the over the term of the related guarantee. It is Consolidated Financial Statements of PG&E noted that the liability would typically be Corporation or the Utility.

reduced by a credit to earnings as the guarantor is released from risk under the guarantee. Please refer to the Stock-Based Compensation section of this Note 1 for additional information.

The initial recognition and initial measurement provisions apply on a prospective basis to Changefrom Gross to Net Metbod of guarantees issued or modified after ReportingRevenues and Expenses on December 31, 2002. PG&E Corporation is Trading Activities - Effective for the quarter currently evaluating the impact of FIN 45's initial ended September 30, 2002, PG&E Corporation recognition and measurement provisions on its changed its method of reporting gains and losses Consolidated Financial Statements. The associated with energy trading contracts from the disclosure requirements for FIN 45 are effective gross method of presentation to the net method.

for financial statements of interim or annual PG&E Corporation believes that the net method periods ending after December 15, 2002, and provides a more accurate and consistent have been incorporated into PG&E Corporation's presentation of energy trading activities on the December 31, 2002, disclosures of guarantees in financial statements. Amounts to be presented these footnotes. under the net method include all gross margin elements related to energy trading activities, Accounting for Stock-Based including both unrealized and realized trades Compensation - Transition and and both physical and financial trades.

Disclosures - On December 31, 2002, the FASB issued SPAS No. 148, "Accounting for Stock- Before implementation of the net method, PG&E Based Compensation - Transition and Corporation already had reported unrealized Disclosures, an Amendment of FASB Statement gains and losses on trading activities on a net No. 123." This Statement provides alternative basis in operating revenues. However, PG&E methods of transition for companies who Corporation had reported realized gains and voluntarily change to the fair value-based losses on a gross basis in operating income, as method of accounting for stock-based employee both operating revenues and costs of commodity compensation in accordance to SFAS No. 123, sales and fuel. PG&E Corporation is now "Accounting for Stock-Based Compensation." reporting all gains and losses from trading SPAS No. 148 does not permit the use of the activities, including amounts that are realized, on original SFAS No. 123 prospective method of a net basis as operating revenues. This will transition for changes to the fair value based provide greater consistency in reporting the method made in fiscal years beginning after results of all energy trading activities. All prior December 15, 2003. The Statement also requires year financial statements have been reclassified prominent disclosures in both annual and interim to conform to the net method.

financial statements about the method of accounting for stock-based compensation and Implementation of the net method has no net the effect of the method used on reported effect on gross margin, operating income, or net 87

income. Accordingly, PG&E Corporation impacted by the change in methodology on continues to report realized income from PG&E Corporation's Consolidated Statements of non-trading activities on a gross basis in Operations for the years ended December 31, operating revenues and operating expenses. The 2001 and 2000.

schedule below summarizes the amounts Prior Method of Presentation As Presented (in millions) (Gross Method) (Net Method) 2001 2000 2001 2000 Energy commodities and services(" .......................... $11,647 $15,809 $1,841 $3,062 Cost of energy commodities and services(2) .... ................ 11,026 14,933 1,220 2,186 Net subtotal ......... .............................. $ 621 $ 876 $ 621 $ 876

" These amounts, as presented in the net method, differ from the financial statements due to the exclusion of equity earnings in affiliates, and eliminations and other, which arnounted to net charges of $93 million and $131 million at December 31, 2001, and 2000, respectively.

( These amounts, as presented in the net method, differ from the financial statements due to the exclusion of eliminations and other, which amounted to net charges of $172 million and $196 million at December 31, 2001, and 2000, respectively.

Rescission of EITF 98 In October 2002, estimated impact of the first quarter 2003 the Emerging Issues Task Force (EITF) rescinded cumulative effect of a change in accounting EITF Issue No. 98-10, "Accounting for Contracts principle is a loss of $5 million, net of taxes at Involved in Energy Trading and Risk December 31, 2002.

Management Activities." Energy trading contracts that are derivatives in accordance with SFAS Change in Estimate Due to Changes in No. 133, "Accounting for Derivative Instruments CertainFairValue Assumptions - PG&E and Hedging Activities," as amended by SFAS Corporation estimates the gross mark-to-market No. 138, "Accounting for Certain Derivative value of its trading contracts and certain Instruments and Certain Hedging Activities" non-trading contracts using forward curves. The (collectively, SFAS No. 133), will continue to be forward curves used to calculate mark-to-market accounted for at fair value under SFAS No. 133. value have liquid periods (includes continuous Contracts that were previously marked to market maturities starting from the month for which as trading activities under EITF 98-10 that do not broker quotes are available on a daily basis) and meet the definition of a derivative will be illiquid periods (includes those maturities for recorded at cost, with a one-time adjustment to which broker quotes are not readily available).

be recorded as a cumulative effect of a change When market data is not available, PG&E in accounting principle as of January 1, 2003. For Corporation historically has utilized alternative PG&E Corporation, the majority of trading pricing methodologies, including third-party contracts are derivative instruments as defined in pricing curves, the extrapolation of forward SFAS No. 133. The rescission of EITF 98-10 has pricing curves using historically reported data, no effect on the accounting for derivative and interpolation between existing data points.

instruments used for non-trading purposes, The gross mark-to-market valuation is then which continue to be accounted for in adjusted for time value of money, accordance with SFAS No. 133. creditworthiness of contractual counterparties, market liquidity in future periods, and other The reporting requirements associated with the adjustments necessary to determine fair value.

rescission of EITF 98-10 are to be applied For trading activities, these models are used to prospectively for all Er1F 98-10 energy trading estimate the fair value of long-term transactions contracts entered into after October 25, 2002. For including certain tolling agreements. For all EIW 98-10 energy trading contracts in non-trading activities, these models are used to existence at or prior to October 25, 2002, the estimate the fair value of certain derivative 88

contracts accounted for as cash flow hedges or debt extinguishment be classified as at fair value through earnings under SFAS extraordinary items. Instead, such gains and No. 133. losses will generally be classified as interest expense. During 2002, PG&E Corporation Beginning in the third quarter of 2002, PG&E recorded $115 million of debt extinguishment Corporation implemented a new model for losses as a charge to interest expense relating to projecting forward power and gas prices during note prepayments and ratings waiver extensions.

illiquid periods. This new process primarily impacts the estimation of power prices. The In addition, SFAS No. 145 eliminates an model estimates forward power prices in illiquid inconsistency in lease accounting by requiring periods using the mid-point of the marginal cost that modifications of capital leases that result in curve (the lowest variable cost of generation reclassification as operating leases be accounted available in a particular region) and the forecast for consistently with sale-leaseback accounting curve (the price at which a generation unit will rules. This provision did not have any impact on recover its capital costs and a return on the Consolidated Financial Statements of PG&E investment). Assumptions about cost recovery Corporation or the Utility at the date of adoption.

are combined with assumptions about volatility and correlation in an option model to project Changes to Accounting for Certain forward power prices. Interpolation methods Derivative Contracts- On April 1, 2002, PG&E continue to be used for intermediate periods Corporation implemented two interpretations when broker quotes are intermittent. In addition issued by the FASB's Derivatives Implementation to implementing the new process for projecting Group (DIG). DIG Issues C15 and C16 changed forward power prices in illiquid periods, PG&E the definition of normal purchases and sales Corporation also enhanced its models to better included in SFAS No. 133. Previously, certain incorporate certain physical characteristics of its derivative commodity contracts for the physical power plants, and to account for uncertainties delivery of purchase and sale quantities surrounding projected forward prices, volumetric transacted in the normal course of business were assumptions, and modeling complexity. PG&E exempt from the requirements of SFAS No. 133 Corporation also refined its process for under the normal purchases and sales exception, estimating the bid-ask spread in illiquid periods and thus were not marked to market and for purposes of liquidity adjustments. reflected on the balance sheet like other derivatives. Instead, these contracts were All of these changes in fair values are being recorded on an accrual basis.

accounted for on a prospective basis as a change in accounting estimate. The change in fair values DIG C15 changed the definition of normal had a pre-tax income effect of a $14 million loss purchases and sales for certain power contracts.

from trading activities and a pre-tax gain of DIG C16 disallowed normal purchases and sales

$25 million from non-trading activities. These treatment for commodity contracts (other than income effects, totaling a pre-tax gain of power contracts) that contain volumetric

$11 million for both trading and non-trading variability or optionality. PG&E NEG determined activities, were recognized in the quarter ended that five of its derivative commodity contracts for September 30, 2002. the physical delivery of power and purchase of fuel no longer qualified for normal purchases Accounting for Gains and Losses on Debt and sales treatment under these interpretations.

Extinguisbment and CertainLease Beginning April 1, 2002, these five contracts Modifications - On July 1, 2002, PG&E were required to be recorded on the balance Corporation adopted SFAS No. 145, "Rescission sheet at fair value and marked to market through of FASB Statements No. 4, 44, and 64, earnings. Three of the contracts had positive Amendment of FASB Statement No. 13, and market values and resulted in pre-tax income of Technical Corrections." This Statement eliminates $125 million. The remaining two contracts had the current requirement that gains and losses on negative market values that resulted in a pre-tax 89

charge of $127 million. The cumulative effects of subsequent years' impacts (assuming that the implementing these accounting changes at affected contracts are held to their expiration).

April 1, 2002, resulted in PG&E Corporation recording price risk management assets of Accountingfor the Impairment or Disposal

$37 million, price risk management liabilities of of Long-Lived Assets - On January 1, 2002,

$255 million, and a reduction of out-of-market PG&E Corporation adopted SEAS No. 144, obligations of $129 million reclassified to net "Accounting for the Impairment or Disposal of price risk management liabilities. Long-Lived Assets." SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of One of the contracts with a positive market Long-Lived Assets and for Long-Lived Assets to value included above is a power sales contract at be Disposed of," but retains its fundamental a partnership in which PG&E NEG has a provision for recognizing and measuring 50 percent ownership interest. PG&E NEG impairment of long-lived assets to be held and reflects its investment in this partnership on an used. This Statement requires that all long-lived equity basis (Investments in Unconsolidated assets to be disposed of by sale be carried at the Affiliates). Upon adoption of DIG C15 and C16, lower of carrying amount or fair value less cost PG&E NEG recognized its equity share of the to sell, and that depreciation cease to be gain from the cumulative change in accounting recorded on such assets. SEAS No. 144 method and correspondingly increased the book standardizes the accounting and presentation value of its equity investment in the partnership. requirements for all long-lived assets to be However, the future net cash flows from the disposed of by sale, and supersedes previous partnership do not support the increased equity guidance for discontinued operations of business investment balance. Therefore, PG&E NEG has segments. The initial adoption of this Statement recognized an impairment charge of $101 million at January 1, 2002, did not have any impact on to reduce its equity-method investment to fair the Consolidated Financial Statements of value. PG&E NEG. During 2002, PG&E NEG recorded certain impairment charges in accordance with The cumulative effect of the change in SEAS No. 144 (see Note 6, "Discontinued accounting principle for DIG C15 and C16 was a Operations" and Note 7, "Impairments, net charge of $61 million, after-tax, and included Write-offs, and Other Charges").

the recognition of the fair market value of the five contracts impacted by DIG C15 and C16 and Accountingfor Goodwill and Otber the impairment charge for the equity method Intangible Assets - On January 1, 2002, PG&E investment. The Utility was not impacted by Corporation adopted SPAS No. 142, "Goodwill these accounting changes. and Other Intangible Assets." This Statement eliminates the amortization of goodwill and Implementation of these accounting changes will requires that goodwill be reviewed at least not impact the timing and amount of cash flows annually for impairment. Upon implementation associated with the affected contracts; however, of this Statement, the transition impairment test it will impact the timing and magnitude of future for goodwill was performed as of January 1, earnings. Future earnings will reflect the gradual 2002, and no impairment loss was recorded.

reversal of the assets and liabilities recorded Goodwill amortization expense was $5 million in upon adoption over the contracts' lives, as well 2001 and 2000. During 2002, PG&E NEG as any prospective changes in the market value recorded a charge for impairment of goodwill in of the contracts. Prospective changes in the accordance with SPAS No. 142 (see Note 7, market value of these contracts could result in Impairment, Write-offs, and Other Charges). The significant volatility in earnings. However, over Utility had no goodwill on its balance sheet at the total lives of the contracts, there will be no December 31, 2002, or December 31, 2001.

net impact to total operating results after netting the cumulative effect of adoption against the This Statement also requires that the useful lives of previously recognized intangible assets be 90

reassessed and the remaining amortization Under the Statement, the asset retirement periods be adjusted accordingly. Adoption of this obligation is recorded at fair value in the period Statement did not require any adjustments to be in which it is incurred by increasing the carrying made to the useful lives of existing intangible amount of the related long-lived asset. In each assets and no reclassifications of intangible assets subsequent period, the liability is accreted to its to goodwill were necessary. present value and the capitalized cost is depreciated over the useful life of the related Intangible assets other than goodwill are being asset. Upon adoption, the cumulative effect of amortized on a straight-line basis over their applying this Statement will be recognized as a estimated useful lives, and are reported under change in accounting principle in the non-current assets in the Consolidated Balance Consolidated Statements of Operations. However, Sheets. rate-regulated entities may recognize regulatory assets or liabilities as a result of timing The schedule below summarizes the amount of differences between the recognition of costs as intangible assets by major classes: recorded in accordance with this statement and costs recovered through the ratemaking process.

(in mll[on') Balance at December 31,

.. . Regulatory assets and liabilities may be recorded 2002 2001 Gross when it is probable that the asset retirement can~rry W Accumulted Canobtg Accumulated costs will be recovered through the ratemaking Amoun At Amortizaton Amount Amortiation process.

PG&E NEG:

Service aRvments . S 33 $7 $33 $6 Power salc PG&E Corporation estimates the impact of agreerncniw

. I i Other agrmeffnL,. . 12 6 217 8 adopting SFAS No. 143 effective January 1, 2003, Utility: will be as follows:

Hydro liknnm and other agremcnt. . 67 16 66 14

• The Utility will adjust its nuclear PG&E CorpMruion decommissioning obligation to reflect the Consolidtt .e . . $126 $38 $141 $33 fair value of decommissioning its nuclear power facilities. The Utility will also PG&E NEG's amortization expense on intangible recognize asset retirement obligations assets was $7 million in 2002, $3 million in 2001, associated with the decommissioning of and $4 million in 2000. The Utility's amortization other fossil generation assets.

expense of intangible assets was $3 million in 2002, $2 million in 2001, and $2 million in 2000. At December 31, 2002, the total nuclear decommissioning obligation accrued was

$1.3 billion and is included in The following schedule shows the estimated amortization expenses for intangible assets for accumulated depreciation and full years 2003 through 2007. decommissioning on the Consolidated Balance Sheets (see Note 13, "Nuclear (in mIllons) 2003 2004 2005 2006 2007 Decommissioning"). The Utility has accrued, at December 31, 2002, PG&E NEG ... $4 $3 $3 $3 $3

$52 million to decommission certain fossil Utility .. $3 $3 $3 $3 $3 generation assets based on its estimate of the decommissioning obligation under the Accountingfor Asset Retirement accounting principles in effect at that Obligations - In June 2001, the FASB issued time. These decommissioning obligations SFAS No. 143, "Accounting for Asset Retirement are also included in accumulated Obligations." PG&E Corporation and the Utility depreciation and decommissioning on the will adopt this Statement effective January 1, Consolidated Balance Sheets.

2003. SFAS No. 143 provides accounting requirements for costs associated with legal The Utility estimates it will recognize an obligations to retire tangible, long-lived assets. adjustment to its recorded nuclear and 91

fossil facility decommissioning obligations December 31, 2002, have matured and have in the range of an increase of $222 million been reinvested.

to a decrease of $192 million for asset retirement obligations in existence as of At December 31, 2002, two funds held balances January 1, 2003. The estimated cumulative greater than 10 percent of PG&E Corporation's effect of a change in accounting principle and the Utility's cash and cash equivalents from unrecognized accretion expense and balance. They were the Citifunds Institutional adjustments to depreciation and Liquid Reserves Fund and the Fiduciary Trust decommissioning expense accrued to date Company International.

will range from a loss of $19 million to a gain of $17 million (pre-tax). Restricted Casb

• PG&E NEG estimates that it will recognize Restricted cash includes cash and cash a liability in the range of $11 million to equivalents, as defined above, which are

$21 million for asset retirement obligations (1) restricted under the terms of certain on January 1, 2003. The cumulative effect agreements for payment to third parties, and of a change in accounting principle from (2) held in escrow as collateral required by the unrecognized accretion and depreciation California Independent System Operator (ISO) expense is estimated to be a loss in the and other counterparties.

range of $4 million to $6 million (pre-tax).

The impact to PG&E NEG of Inventories implementing SFAS No. 143 by its unconsolidated affiliates is expected to be Inventories include materials and supplies, gas immaterial.

stored underground, coal, and fuel oil. Materials, supplies, and gas stored underground are valued Casb and Cash Equivalents at average cost. Coal and fuel oil are valued using the last-in first-out method. PG&E ET's Invested cash and other investments with natural gas inventory is valued at cost as original maturities of three months or less are discussed in Note 1, Recission of EITF 98-10.

considered cash equivalents. Cash equivalents are stated at cost, which approximates fair value.

Income Taxes PG&E Corporation's and the Utility's cash equivalents are held in a variety of funds that PG&E Corporation and the Utility use the liability mainly invest in:

method of accounting for income taxes. Income

• Certificates of deposit and time deposits; tax expense (benefit) includes current and deferred income taxes resulting from operations

. Bankers' acceptances and other short-term during the year. Investment tax credits are securities issued by banks; amortized over the life of the related property.

• Asset-backed securities; Other tax credits, primarily synthetic fuel tax credits, are recognized in income as earned.

• Repurchase agreements;

• High-grade commercial paper; and PG&E Corporation files a consolidated U.S.

(federal) income tax return that includes

. Discounted notes issued or guaranteed by domestic subsidiaries in which its ownership is the United States government or its 80 percent or more. In addition, PG&E agencies.

Corporation files combined state income tax returns where applicable. PG&E Corporation and In general, the securities are purchased on the the Utility are parties to a tax-sharing date of issue and held in the accounts until arrangement under which the Utility determines maturity. Substantially all of PG&E Corporation's its income tax provision (benefit) on a stand-and the Utility's cash equivalents on hand at alone basis.

92

PG&E NEG is included in the consolidated tax the determination of the gain or loss on return of PG&E Corporation. Certain creditors of disposition.

PG&E NEG have asserted that past payments from tax benefits gave rise to an implied tax Depreciation sharing agreement between PG&E Corporation and PG&E NEG. PG&E Corporation disputes this Property, plant and equipment are depreciated assertion. on a straight-line basis over estimated useful lives, less any residual or salvage value.

Property, Plant and Equipment Year ended Composite depreciation rates December 31, Property, Plant and Equipment are reported at its 2002 2001 2000 original cost, unless impaired under the PG&E Corporation ..... ...... 3.36% 3.07% 4.496 provisions of SAFS No. 144. Original costs Utility ................... 3.42% 3.63% 4.54%

include:

• Labor and materials; Estirnated usefiu lives Utility PG&E NEG

. Construction overhead; and Electric generating facilities .......... 15 to 50 years 20 to 50 years

• Capitalized interest or an allowance for Electric distribution funds used during construction (AFUDC). facilities .......... 16 to 63 years N/A Electric transmission .... 27 to 65 years N/A Gas distribution facilities . 28 to 49 years N/A AFUDC is the estimated cost of debt and equity Gas transmission ...... 25 to 45 years 15 to 40 years funds used to finance regulated plant additions Gas storage ......... 25 to 48 years N/A that is allowed to be recorded as part of the Other ............. 5 to 40 years 2 to 20 years costs of construction projects. AFUDC is recoverable from customers through rates once The useful lives of the Utility's property, plant the property is placed in service. and equipment are authorized by the CPUC.

Depreciation rates include a component for the CapitalizedInterest and AFUDC cost of asset retirement net of salvage value. The Utility has a separate rate component for the I Year ended accrual of its recorded obligation for nuclear (in millions) ecember 31, decommissioning which is included in 2002 2001 2000 depreciation, amortization, and decommissioning PG&E Corporation .... ....... $42 $22 $19 expense in the accompanying Consolidated Utility ................... 27 18 18 Statements of Operations. The accrued net asset retirement obligation is included in accumulated PG&E Corporation and the Utility periodically depreciation and decommissioning in the evaluate long-lived assets, including property, accompanying Consolidated Balance Sheets.

plant and equipment, when events or changes in circumstances indicate that the carrying value of Refer to the section "Accounting for the these assets may be impaired. Impairment or Disposal of Long-Lived Assets" in this Note and Note 7 "Impairment, Write-offs, PG&E Corporation charged the original cost of and Other Charges" for a discussion of retired plant and removal costs less salvage value impairment and the effect on Property, Plant and to accumulated depreciation upon retirement of Equipment.

plant in service for the Utility and for PG&E NEG's lines of business that apply SPAS No. 71, Nuclear Fuel "Accounting for the Effects of Certain Types of Regulation," as amended. For the remainder of Property, plant and equipment includes nuclear PG&E NEG business operations, the cost and fuel inventories. Stored nuclear fuel inventory is accumulated depreciation of property, plant and stated at weighted average cost. Nuclear fuel in equipment retired or otherwise disposed of from the reactor is amortized based on the amount of related accounts are included in the amounts in energy output.

93

CapitalizedSoftware Costs net accounts receivable, short-term borrowings, debt in default, and accounts PG&E Corporation capitalizes costs incurred payable, approximate their carrying values during the application development stage of as of December 31, 2002, and 2001; internal use software projects to property, plant

• The fair value of the Utility's debt, for and equipment. Capitalized software costs which no market quotations are readily totaled $349 million at December 31, 2002, and available, is obtained from third-party

$269 million at December 31, 2001, net of accumulated amortization of $154 million at experts with extensive experience in the December 31, 2002, and $112 million at fair valuation of such instruments. The fair value of a small portion of the Utility's December 31, 2001. PG&E Corporation amortizes debt is determined using the present capitalized software costs ratably over the value of future cash flows; and expected lives of the projects ranging from 3 to 15 years, commencing operational use, in

• The fair values of nuclear accordance with regulatory requirements. decommissioning funds, rate reduction bonds, the Utility's preferred stock, and Gains and Losses on Debt Extinguisbments the Utility's 7.90 percent deferrable interest subordinated debentures are Gains and losses on debt extinguishments - determined based on quoted market associated with regulated operations that are prices.

subject to the provisions of SFAS No. 71 are deferred and amortized over the remaining Due to the illiquid nature and limited demand original amortization period of the debt for PG&E NEG's long-term debt, the estimated reacquired, consistent with ratemaking principles. fair value at December 31, 2002, was not able to Gains and losses on debt extinguishments be determined. At December 31, 2001, PG&E associated with unregulated operations are NEG's long-term receivables had a carrying value recognized at the time such debt is reacquired, of $536 million and estimated fair value of and upon adoption of SFAS No. 145 on July 1, $467 million. At December 31, 2001, PG&E 2002 are reported as interest expense unless they NEG's long-term debt had a carrying value of were determined to be unusual and infrequent, $3.4 billion and an estimated fair value of in which case they would be reported as $3.5 billion.

extraordinary gains or losses.

The carrying amount and fair value of PG&E FairValue of FinancialInstruments Corporation's and the Utility's financial instruments are as follows (the table below The fair value of a financial instrument excludes financial instruments with fair values represents the amount at which the instrument that approximate their carrying values, as these could be exchanged in a current transaction instruments are presented on the Consolidated between willing parties, other than in a forced Balance Sheets):

sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts.

PG&E Corporation used the following methods and assumptions in estimating fair value disclosures for financial instruments:

• The fair values of cash and cash equivalents, restricted cash and deposits, 94

(inmllions) Aet December 31, (In millions) At December 31, 2002 2001 Carrying Fair Carrying Fair Amount Value Amount Value Nuclear decommissioning funds (Note 13):

Utility......................................... $1,335 $1,335 $1,337 $1,337 Long-term debt (Note 4).

PG&E Corporation ................................ 1,000 1,000 1,000 1,000 Utility ......................................... 4,820 4,631 5,153 4,975 Rate reduction bonds (Note 5):

Utility......................................... 1,450 1,580 1,740 1,811 Utility preferred stock with mandatory redemption provisions (Note 10): .......................... 137 132 137 109 7.90 Percent cumulative quarterly income preferred securities (Note 4) ............................... - - 300 246 7.90 Percent deferrable interest subordinated debentures (Note 4)............................... 300 275 - _

Regulation and Statement of Financial Regulatory Assets Accounting Standards No. 71 Regulatory assets comprise the following:

PG&E Corporation and the Utility account for the Balance at financial effects of regulation in accordance with (in millions) December 31, SFAS No. 71. SFAS No. 71 applies to regulated 2002 2001 entities whose rates are designed to recover the Rate reduction bond assets ..... . . . . . $1,346 i 1,636 costs of providing service. The Utility is Unamortized loss, net of gain, on regulated by the CPUC, the FERC, and the reacquired debt ..... .......... 299 322 Nuclear Regulatory Commission (NRC), among Regulatory assets for deferred income tax 229 188 others. The gas transmission business in the Other, net ........... . .. .. . .. . 137 137 Pacific Northwest is also regulated by the FERC. Total Utility regulatory assets ..... . . . 2,011 2,283 PG&E GTN .......... . .. . .. . . . 42 36 SFAS No. 71 provides for the recording of Total PG&E Corporation regulatory assets $2,053 $2,319 regulatory assets and liabilities when certain conditions are met. Regulatory assets represent Regulatory assets are charged to expense during the capitalization of incurred costs that would the period that the costs are reflected in otherwise be charged to expense when it is regulated revenues.

probable that the incurred costs will be included for ratemaking purposes in the future. Regulatory The Utility's regulatory asset related to rate liabilities represent rate actions of a regulator reduction bonds is amortized simultaneously that will result in amounts that are to be credited with the amortization of the rate reduction to customers through the ratemaking process. bonds, and will be fully recovered by the end of 2007. The Utility's regulatory asset related to the If portions of the Utility's or PG&E GTN's unamortized loss, net of gain, on reacquired debt operations no longer become subject to the will be recovered over the remaining original provisions of SFAS No. 71, a write-off of related amortization period of the reacquired debt over regulatory assets and liabilities would be periods ranging from 1 to 24 years. The Utility's required, unless some form of transition cost regulatory assets related to deferred income tax recovery continues through rates established and will be recovered over the period of reversal of collected for the remaining regulated operations. the accumulated deferred taxes to which they relate. Based on current regulatory ratemaking and income tax laws, the Utility expects to 95

recover deferred income tax-related regulatory balancing accounts accumulate differences assets over periods ranging from 1 to 39 years. between recorded costs and costs the Utility is authorized to recover through rates. Under-In general, the Utility does not earn a return on collections that are probable of recovery are regulatory assets where the related costs do not recorded as regulatory balancing account assets.

accrue interest. At December 31, 2002, the Utility Over-collections are recorded as regulatory did not earn a return on regulatory assets related balancing account liabilities. The Utility's to deferred income taxes of $229 million. regulatory balancing accounts accumulate balances until they are refunded to or received Regulatory Liabites from Utility customers through authorized rate adjustments.

Regulatory Liabilities comprise the following:

As a result of the California energy crisis Balance at (in millions) December 31, discussed in Note 2, the Utility could no longer 2002 2001 conclude that power-generation and Employee benefit plans ............ $1,102 $1,133 procurement-related balancing accounts meet the Public purx)se programs ........... 182 218 requirements of SFAS No. 71. However, the Rate reduction bonds ............. 102 17 Utility continues to record balancing accounts Other ....................... 75 117 associated with its electricity and gas distribution Total Utility regulatory liabilities ...... 1,461 1,485 and transmission businesses.

PG&E GIN ................... 14 12 Total PG&E Corporation regulatory In 2002, the CPUC ordered the Utility to create liabilities ................... $1,475 $1,497 certain electric balancing accounts to track specific electric-related costs but has not yet The Utility's regulatory liabilities related to determined the recovery method for these costs.

employee benefit plan expenses represent the In the decisions ordering the creation of these cumulative differences between expenses balancing accounts, the CPUC indicated that the recognized for financial accounting purposes and recovery method of these amounts would be expenses recognized for ratemaking purposes. determined in the future. Because the Utility These balances will be charged against expense cannot conclude that the amounts in these to the extent that future financial accounting balancing accounts are considered probable of expenses exceed amounts recoverable for recovery in future rates, the Utility has reserved regulatory purposes. The Utility's regulatory these balances by recording a charge against liabilities related to public purpose programs earnings. As of December 31, 2002, the reserve represent revenues designated for public for these balances was $136 million.

purpose program costs that are expected to be incurred in the future. The Utility's regulatory The Utility's current regulatory balancing account liability for rate reduction bonds represents the assets comprise the following:

deferral of over-collected revenue associated Balance at with the rate reduction bonds that the Utility (in millions) December 31, expects to return to ratepayers in the future. 2002 2001 Gas Revenue Balancing Accounts .... $65 $42 Regulatory BalancingAccounts Gas Cost Balancing Accounts ....... 33 25 Electric Distribution Cost Balancing Sales balancing accounts accumulate differences Accounts .................. 8 between recorded revenues and revenues the Total ...................... $98 $75 Utility is authorized to collect through rates. Cost 96

The Utility's current regulatory balani :ing account needed by the Utility's customers that could not liabilities comprise the following: be met by the Utility's purchased power contracts and retained generation facilities. Under (in smons) I Balane 31a California law, the DWR is deemed to sell the 21002 2001 electricity directly to the Utility's retail customers, Gas Revenue Balancing Accounts .... 4 5 31 not to the Utility. Therefore, the Utility is a pass-Gas Cost Balancing Accounts ....... 226 178 through entity for transactions between its Electric Transmission and Distribution customers and the DWR. Although charges for Revenue Balancing Accounts ..... 98 151 electricity provided by the DWR are included in Electric Transmission Cost Balancing the amounts the Utility bills its customers, the Accounts ..................

32 - Utility deducts from electric revenues amounts Total ...................... S360 $360 passed through to the DWR. The pass-through amounts are based on the DWR's CPUC-The Utility expects to collect from or refund to approved revenue requirement and are excluded its ratepayers the balances included in current from the Utility's electric revenues in its balancing accounts receivable and payable Consolidated Statements of Operations.

within the next twelve months. Regulatory balancing accounts that the Utility does not In accordance with EITF 98-10 and SFAS expect to collect or refund in the next twelve No. 133, certain energy trading contracts that are months are included in non-current regulatory not designated as hedging instruments or as assets and liabilities. normal purchase and sale contracts, are recorded at fair value using mark-to-market accounting, Revenue Recognition which records a change in fair value as income (or a charge) on the income statement, and Revenues are recorded in accordance with the correspondingly adjusts the fair value of the Securities and Exchange Commission (SEC) Staff instrument on the balance sheet. Effective Accounting Bulletin (SAB) No. 101, "Revenue January 1, 2003, all non-derivative energy trading Recognition," as amended. contracts that were marked to market under EITF 98-10 will be accounted for using the cost Energy commodities and services revenues method. Please refer to the Adoption of New derived from power generation are recognized Accounting Policies section of this note for upon output, product delivery, or satisfaction of additional information.

specific targets, all as specified by contractual terms. Regulated gas transmission revenues are Revenues from trading activities are reported on recorded as services are provided, based on rate a net basis in operating revenues for both schedules approved by the FERC. Electric utility realized and unrealized gains (and losses).

revenues, which are comprised of generation, Realized revenues and costs of sales from transmission, and distribution services, are billed non-trading activities are reported on a gross to the Utility's customers at the CPUC-approved basis as operating revenues and operating "bundled" electricity rate. Gas utility revenues, expenses, respectively.

which are comprised of transmission and distribution services, are also billed at Accountingfor Price Risk Management CPUC-approved rates. Utility revenues are Activities recognized as gas and electricity are delivered, and include amounts for services rendered but PG&E Corporation, primarily through its not yet billed at the end of each year. subsidiaries, engages in price risk management activities for both non-trading and trading As discussed in Note 2, since January 2001, the purposes. Non-trading activities are conducted to California Department of Water Resources (DWR) optimize and secure the return on risk capital has purchased electricity on behalf of the Utility's deployed within PG&E NEG's existing asset and customers to cover the amount of electricity contractual portfolio. Because of the Utility's credit rating downgrade and subsequent 97

bankruptcy, risk management activities have lines on the PG&E Corporation Consolidated been limited to forward and option contracts Statements of Operations, including energy related to the Utility's natural gas portfolio and commodities and services revenue, cost of the continuation of power forward contracts that energy commodities and services, interest were in existence prior to the bankruptcy. income or interest expense, and other income, (expense), net. Changes in the market value of PG&E Corporation conducts trading activities the trading contracts, resulting primarily from principally through its unregulated lines of newly originated transactions and the impact of business. Trading activities are conducted to commodity prices or interest rate movements, are generate profit, create liquidity, and maintain a recognized in operating income in the period of market presence. Net open positions often exist change. On an unrealized and a realized basis, or are established due to PG&E NEG's PG&E Corporation now recognizes trading assessment of and response to changing market contracts on a net basis as previously described conditions. in this Note.

PG&E NEG is significantly reducing their energy As described more fully in this Note under trading operations. Change in Estimate Due to Changes in Certain Fair Value Assumptions, for non-trading and Derivatives associated with both non-trading and trading contracts, models are used to estimate trading activities include forward contracts, the fair value of derivatives and other contracts futures, swaps, options, and other contracts. that are accounted for as derivative contracts.

Gross mark-to-market value is estimated using Derivative instruments associated with the midpoint of quoted bid and ask prices for non-trading activities are accounted for at fair liquid periods and, for illiquid periods, using the value in accordance with SFAS No. 133 and midpoint of the marginal cost curve and the ongoing interpretations of the FASB's DIG. forecast curve. Interpolation methods are used Derivative and other financial instruments for intermediate periods when broker quotes are associated with trading activities in electric and intermittent. The gross mark-to-market valuation other energy commodities are accounted for at is then adjusted for time value of money, fair value in accordance with SPAS No. 133 and creditworthiness of contractual counterparties, EITF 98-10, subject to the transition requirements market liquidity in future periods, and other of the rescission of EITF 98-10 discussed above. adjustments necessary to determine fair value.

Both non-trading and trading derivatives are PG&E Corporation engages in non-trading classified as price risk management assets and activities to hedge the impact of market price risk management liabilities in the fluctuations on energy commodity prices, interest accompanying Consolidated Balance Sheets. rates, and foreign currencies. Before the Non-trading derivatives, or any portion thereof, implementation of SFAS No. 133, PG&E that are not effective hedges are adjusted to fair Corporation and the Utility accounted for value through income. For non-trading hedging activities under the deferral method, derivatives that are effective hedges, changes in whereby unrealized gains and losses on hedging the fair value are recognized in accumulated transactions were deferred. When the underlying other comprehensive income (loss) until the item settled, PG&E Corporation and the Utility hedged item is recognized in earnings. recognized the gain or loss from the hedge Derivatives associated with trading activities are instrument in operating income. In instances adjusted to fair value through income, subject to where the anticipated correlation of price the effects of the rescission of EITF 98-10 movements did not occur, hedge accounting was discussed above. terminated and future changes in the value of the derivative were recognized as gains or losses.

Net realized gains or losses on non-trading If the hedged item was sold, the value of the derivative instruments for the year ended associated derivative was recognized in income.

December 31, 2002, were included in various 98

Effective January 1, 2001, PG&E Corporation and longer qualifies for normal purchases and sales the Utility adopted SFAS No. 133 that requires treatment, and must be marked-to-market that all derivatives, as defined, are recognized on through earnings. The cumulative effect of this the balance sheet at fair value. PG&E change in accounting principle increased Corporation's transition adjustment to implement earnings by approximately $9 million (after-tax).

SFAS No. 133 on January 1, 2001, resulted in a non-material decrease to earnings and an Stock-Based Compensation after-tax decrease of $333 million to accumulated other comprehensive income. The Utility's PG&E Corporation and the Utility account for transition adjustment to implement SFAS No. 133 stock-based compensation using the intrinsic resulted in a non-material decrease to earnings value method in accordance with the provisions and an after-tax $90 million positive adjustment of APB No. 25, as allowed by SFAS No. 123, as to accumulated other comprehensive loss. These amended by SFAS No. 148. Under the intrinsic transition adjustments, which relate to hedges of value method, PG&E Corporation and the Utility interest rate, foreign currency, and commodity do not recognize any compensation expense, as price risk exposure, were recognized as of the exercise price of all stock options is equal to January 1, 2001, as a cumulative effect of a the fair market value at the time the options are change in accounting principle. granted. Had compensation expense been recognized using the fair value-based method PG&E Corporation and the Utility also have under SFAS No. 123, PG&E Corporation's pro derivative commodity contracts for the physical forma consolidated earnings (loss) and earnings delivery of purchase and sale quantities (loss) per share would have been as follows:

transacted in the normal course of business.

(In millions, except per Year endcd These derivatives are exempt from the share amounts) December 31, requirements of SFAS No. 133 under the normal 2002 2001 2000 purchase and sales exception, and are not Net earnings (loss):

reflected on the balance sheet at fair value. The As repoted............ $ (874) $1,099 $(3,364)

FASB has approved two interpretations issued by Deduct: Total stock-based the DIG that changed the definition of normal employee compensation expense determined under purchases and sales for certain power contracts. fair value based method As previously described in this Note under for all awards, net of "Changes to Accounting for Certain Derivative related tax effects ...... (20) (23) (10)

Contracts," PG&E Corporation implemented Profonna .............. $ (894) $1,076 $(374) these interpretations on April 1, 2002.

Basic earnings (loss) per shae To qualify for the normal purchases and sales As reported ............. 5(2.36) $ 3.03 $ (9.29) exemption from SFAS No. 133, a contract must Proforma .............. 5(2.41) $ 2.96 $ (9.32) have pricing that is deemed to be clearly and Diluted earnings (loss) per closely related to the asset to be delivered under shae As reported ............. $(2.36) $ 3.02 $ (9.29) the contract. In 2001, the FASB approved another Proforna .............. $(2.41) $ 2.96 $ (9.32) interpretation issued by the DIG that clarifies how this requirement applies to certain Had compensation expense been recognized commodity contracts. In applying this new DIG using the fair value-based method under SFAS guidance, PG&E Corporation determined that No. 123, the Utility's pro forma consolidated one of its derivative commodity contracts no 99

earnings (loss) and earnings (loss) per share and a plan for recovery of generation-related would have been as follows: costs that were expected to be uneconomic under the new market framework (transition (in mi]Cons, except per Year ended share amounts) December 31, costs). Additionally, the CPUC strongly 2002 2001 2000 encouraged the Utility to sell more than Net earnings (loss). 50 percent of its fossil fuel-fired generation As reported ............ $1,794 $1,015 $(3,483) facilities and made it economically unattractive Deduct: Total stock-based for the Utility to retain its remaining generation employee compensation facilities. The new market framework called for expense determined under the creation of the Power Exchange (PX) and the fair value based method for all awards, net of related tax Independent System Operator (ISO). Before it effects .............. (7) (7) (5) ceased operating in January 2001, the PX Proforma .............. $1,787 $1,008 $(3,488) established market-clearing prices for electricity.

The ISO's role is to schedule delivery of electricity for all market participants and operate Accumulated Otber Comprebensive Income certain markets for electricity. Until (Loss) December 15, 2000, the Utility was required to sell all of its owned and contracted generation Accumulated other comprehensive income (loss) to, and purchase all electricity for its retail reports a measure for accumulated changes in customers from, the PX. Customers were given equity of an enterprise that results from the choice of continuing to buy electricity from transactions and other economic events other the Utility or buying electricity from independent than transactions with shareholders. PG&E power generators or retail electricity suppliers Corporation's and the Utility's accumulated other (customers who chose to buy from independent comprehensive income (loss) consists principally power generators or retail electricity suppliers of changes in the market value of certain cash are referred to as direct access customers). Most flow hedges with the implementation of SFAS of the Utility's customers continued to buy No. 133 on January 1, 2001, as well as foreign electricity from the Utility.

currency translation adjustments.

For the seven-month period from June 2000 Reclassifications through December 2000, wholesale electric prices in California averaged $0.18 per Certain amounts in the 2001 and 2000 financial kilowatt-hour (kWh). During this period, the statements have been reclassified to conform to Utility's retail electric rates were frozen and the 2002 presentation. These reclassifications did provided only approximately $0.05 per kWh to not affect the consolidated net income of either pay for the Utility's electricity costs.

PG&E Corporation or the Utility for the years presented. The frozen rates were designed to allow the Utility to recover its authorized utility costs and, NOTE 2: THE UTLI CHAPTER 11 FILING to the extent the frozen rates generated revenues in excess of the Utility's authorized utility costs, Electric Industry Restructuring recover its transitions costs. During the California energy crisis, frozen rates were insufficient to In 1998, California implemented electric industry cover the Utility's electricity procurement and restructuring and established a market other costs. Because the Utility could no longer framework for electric generation in which conclude that its undercollected electricity generators and other power providers were procurement and remaining transition costs were permitted to charge market-based prices for probable of recovery, the Utility charged wholesale power. The restructuring of the

$6.9 billion to expense for these costs at electric industry was mandated by the California December 31, 2000. The Utility's inability to Legislature in Assembly Bill (AB) 1890. The recover procurement costs from customers mandate included a retail electricity rate freeze ultimately resulted in billions of dollars in 100

defaulted debt and unpaid bills and caused the disposition of the Utility's under-collected costs, Utility to file a voluntary petition for relief under if any, remaining at the end of the rate freeze. If Chapter 11 of the Bankruptcy Code in the the CPUC determines that the Utility recovered Bankruptcy Court on April 6, 2001. revenues in excess of its transition costs or in excess of other permitted uses, the CPUC may In January 2001, the CPUC increased electric require the Utility to refund such excess rates by $0.01 per kWh, and in March 2001 by revenues.

another $0.03 per kWh, and restricted use of these surcharge revenues to "ongoing In a case currently pending before it relating to procurement costs" and "future power the CPUC's settlement with Southern California purchases." The Utility had recorded a regulatory Edison (SCE), another California investor-owned liability for these $0.01 and $0.03 surcharge utility (IOU), the Supreme Court of California is revenues when such surcharges exceeded considering whether the CPUC has the authority ongoing procurement costs. to enter into a settlement which allows SCE to recover under-collected procurement and Although the CPUC authorized the $0.03 per transition costs in light of the provisions of kWh surcharge in March 2001, the Utility did not AB 1890. The Utility cannot predict the outcome begin collecting the revenues until June 2001. As of this case or whether the CPUC or others a result, in May 2001, the CPUC authorized the would attempt to apply any ruling to the Utility.

Utility to collect an additional $0.005 per kWh in If the Utility is ordered to refund material revenues for 12 months to make up for the time amounts to ratepayers, the Utility's financial lag in collection of the $0.03 surcharge revenues. condition and results of operations would be Although the collection of this "half-cent" materially adversely affected.

surcharge was originally scheduled to end on May 31, 2002, the CPUC issued a resolution In December 2002, the CPUC issued a decision ordering the Utility to continue collecting the authorizing the Utility to stop tracking amounts half-cent surcharge until further consideration by related to the $0.01 and $0.03 surcharge the CPUC and to record the surcharge revenues revenues in a separate regulatory liability in a balancing account. The Utility had recorded account and instead record them as a reduction a regulatory liability for the $0.005 per kWh to unrecovered transition costs. As a result, in (half-cent) surcharge revenues billed subsequent January 2003, the Utility filed a letter with the May 31, 2002. The regulatory liabilities for the CPUC requesting to withdraw its regulatory

$0.01 per kWh and $0.03 per kWh surcharge liability account used to track the $0.01 and revenues in excess of ongoing procurement $0.03 surcharge revenues in excess of ongoing costs, and half-cent surcharge revenues billed procurement costs.

after May 31, 2002, totaled $222 million as of September 30, 2002, and $65 million as of Based on this December 2002 CPUC decision December 30, 2001. and an agreement between the CPUC and SCE, in which SCE was allowed to use its half-cent In November 2002, the CPUC approved a surcharge to offset its California Department of decision modifying the restrictions on the use of Water Resources (DWR) revenue requirement, revenues generated by the surcharges to permit the Utility reversed its regulatory liabilities the revenues to be used for the purpose of totaling $222 million related to the $0.01 and securing or restoring the Utility's reasonable $0.03 per kWh surcharge revenues in excess of financial health, as determined by the CPUC. The ongoing procurement costs, and half-cent CPUC will determine in other proceedings how surcharge revenues billed subsequent to May 31, the surcharge revenues can be used, whether 2002 during the fourth quarter of 2002. (Of this there is any cost or other basis to support amount, $157 million was originally recorded as specific surcharge levels, and whether the a regulatory liability during 2002; and as such, resulting rates are just and reasonable. After the the reversal of this amount has no impact on CPUC determines when the AB 1890 rate freeze current year earnings.)

ended, the CPUC will determine the extent and 101

During 2001, the price of wholesale electricity implementation of AB 1890. The CPUC stabilized. As a result, the Utility's total scheduled further proceedings to address the generation-related electric revenues were greater impact of AB 6X on the AB 1890 rate freeze for than its generation-related costs. In 2001, this the Utility and to determine the extent and resulted in additional earnings of $458 million disposition of the Utility's remaining unrecovered (after-tax), which represented a partial recovery transition costs. In its November 2002 decision of previously written-off under-collected regarding the surcharge revenues, discussed purchased power and transition costs, and above, the CPUC reiterated that it had yet to included $327 million (after-tax) related to the decide when the rate freeze ended and the market value of terminated bilateral contracts. disposition of any under-collected costs During the year ended December 31, 2002, the remaining at the end of the rate freeze.

Utility's total generation-related revenues exceeded its generation-related costs by The CPUC and the Official Committee of approximately $1.4 billion (after-tax), which Unsecured Creditors (OCC) filed an alternative includes a net reduction of 2001 accrued plan of reorganization in the Utility's bankruptcy purchased power costs of approximately proceeding, proposing that the Utility's overall

$352 million (after-tax) and includes an offset of retail electric rates be maintained at current

$218 million (after-tax) in additional pass-through levels through January 31, 2003, in order to revenues accrued in 2002 related to amounts to generate cash to repay in part the Utility's be remitted to the DWR in connection with the creditors under the CPUC's plan. (See DWR's proposed amendment to the CPUC's "CPUC/OCC's Alternative Plan of Reorganization" May 16, 2002, servicing order. (See further below.) During the third quarter of 2002, the discussion below under "Electricity Purchases.") CPUC represented that since utilities are now The outstanding balance of the Utility's under- required under state law, AB 6X, to retain their collected purchased power and transition costs generating assets and the CPUC has regained its (which were originally $4.1 billion, after-tax) traditional rate authority over those assets, costs amounted to $2.2 billion and $3.6 billion associated with those assets may be recovered (after-tax) at December 31, 2002, and 2001, by the utilities in the traditional way, under respectively. The recovery of these remaining cost-based regulation. Based on these CPUC under-collected purchased power costs and decisions and representations, the Utility believes transition costs will depend on a number of it can continue to record revenues collected factors, including the ultimate outcome of the under its existing overall retail rates, subsequent Utility's bankruptcy and future regulatory and to the statutory end of the rate freeze.

judicial proceedings, including the outcome of the Utility's filed rate doctrine litigation. (The However, the CPUC's proceedings to consider filed rate doctrine litigation refers to a lawsuit the impact of AB 6X on the AB 1890 rate freeze filed in November 2000 in the U.S. District Court and the disposition of the Utility's unrecovered for the Northern District of California by the transition costs are still pending, and it is Utility against the CPUC Commissioners, asking possible that at some future date the CPUC, on the court to declare that the federally approved its own initiative or in response to judicial wholesale electricity costs that the Utility has decisions, including the California Supreme incurred to serve its customers are recoverable in Court's consideration regarding the authority of retail rates under the federal filed rate doctrine.) the CPUC to enter into a settlement which allows SCE to recover under-collected procurement and Under AB 1890, the rate freeze was scheduled to transition costs in light of the provisions of end on the earlier of March 31, 2002, or the date AB 1890, may change its interpretation of law or that the Utility recovered all of its generation- otherwise seek to change the Utility's overall related transition costs as determined by the retail electric rates retroactively. The Utility has CPUC. However, in January 2002, the CPUC not provided reserves for potential refunds of issued a decision finding that new California any of these revenues as of December 31, 2002.

legislation, AB 6X, had materially affected the As a result, any of the changes described above could materially affect the Utility's earnings.

102

In a March 2001 decision, the CPUC adopted an Electricity Purchases accounting proposal by The Utility Reform Network (TURN) that retroactively restates the In January 2001, as wholesale electric prices way in which the Utility's transition costs are continued to exceed retail rates, the major credit recovered. This retroactive change had the effect rating agencies lowered their ratings for the of extending the AB 1890 rate freeze and Utility and PG&E Corporation to non-investment reducing the amount of past wholesale electricity grade levels. Consequently, the Utility lost access costs that could be eligible for recovery from to its bank facilities and capital markets, and customers. The CPUC, the California Supreme could no longer continue buying electricity to Court, and the Bankruptcy Court denied the deliver to its customers. As a result, in the first Utility's request for rehearing. The Utility is quarter of 2001, the California Legislature and currently appealing this matter to the U.S. District the Governor of California authorized the DWR Court for the Northern District of California. The to purchase electricity for the Utility's customers Utility cannot predict the outcome of this matter. and to issue revenue bonds to finance electricity purchases (governed by AB 1X). Initially, the GenerationDivestiture DWR indicated that it intended to buy electricity only at "reasonable prices" to meet the Utility's AB 6X, passed by the California Legislature in net open position, leaving the ISO to purchase January 2001, prohibits utilities from divesting the remainder in order to avoid blackouts. The their remaining power plants before January 1, ISO billed the Utility for its costs to purchase 2006. The Utility believes this law does not electricity to cover the amount of the Utility's net supersede or repeal an existing law requiring the open position not covered by the DWR. In 2001, CPUC to establish a market value for their the Utility accrued approximately $1 billion for remaining generating assets by the end of 2001, these ISO purchases for the period January 17, based on appraisal, sale or other divestiture. The 2001, through April 6, 2001. However, in 2001, Utility has filed comments on this matter with the the FERC issued a series of orders directing the CPUC. However, the CPUC has not yet issued a ISO to buy electricity only on behalf of decision. creditworthy entities. In March 2002, the FERC denied an application for rehearing and On January 17, 2002, the Utility filed an reaffirmed its previous orders finding that the administrative claim with the State of California DWR is responsible for paying such ISO charges.

Victim Compensation and Government Claims Board (the Board) alleging that the new law In February 2002, the CPUC approved decisions violates the Utility's statutory rights under adopting rates for the DWR, and allowing the California's deregulation law (AB 1890). The DWR to collect power charges and financing Utility believes that it has been denied its right to charges from ratepayers to provide the revenues the market value of its retained generating needed by the DWR to procure electricity for the facilities of at least $4.1 billion. On March 7, customers of the Utility and the other California 2002, the Board formally denied the Utility's IOUs for the two-year period ending claim. Having exhausted remedies before the December 31, 2002.

Board, the Utility filed suit for breach of contract in the California Superior Court on September 6, In March 2002, the CPUC modified its 2002. On January 9, 2003, the Superior Court February 2002, DWR revenue requirement granted the State of California's request to decision, effectively lowering the amount dismiss the complaint finding that AB 1890 does allocated to the Utility's customers to $4.4 billion not constitute a contract. The Utility has 60 days for the period from January 2001 through to file an appeal and intends to do so. The December 2002. The DWR's revenue Utility cannot predict what the outcome of any requirement incorporates the procurement of these proceedings will be or whether they will charges previously billed by the ISO and accrued have a material adverse effect on its results of by the Utility. As such, in light of the March 2002 operations or financial condition. FERC order and the February and March 2002, 103

CPUC decisions, in the first quarter of 2002 the Senate Bil 1976 Utility reversed the excess of the ISO accrual (for the period from January 17, 2001, through Under AB 1XY the DWR is prohibited from April 6, 2001) over the amount of the additional entering into new agreements to purchase DWR revenue requirement applicable to 2001, electricity to meet the net open position of the for a net reduction of accrued purchased power California IOUs after December 31, 2002. In costs of approximately $595 million (pre-tax). September 2002, the Governor signed California Senate Bill (SB) 1976 into law. SB 1976 required In October 2002, the DWR filed a proposed that each California IOU submit, within 60 days amendment to the CPUC's May 16, 2002, after the CPUC allocated existing DWR contracts servicing order requesting changes to the for electricity procurement to each California calculation that determines the amount the Utility IOU, an electricity procurement plan to meet the is required to pass through to the DWR. The residual net open position associated with that DWR's proposed amendment changes the utility's customer demand. SB 1976 requires that calculation that determines the amount of each procurement plan include one or more of revenues that the Utility must pass-through to the the following features:

DWR. This proposed amendment would also be

. A competitive procurement process under used to true up previous amounts passed through to the DWR as well as future payments. a format authorized by the CPUC, with the costs of procurement obtained in Under its statutory authority, the DWR may request the CPUC to order utilities to implement compliance with the authorized bidding format being recoverable in rates; such amendments, and the CPUC has approved such amendments in the past without significant

• A clear, achievable, and quantifiable change. In December 2002, the CPUC approved incentive mechanism that establishes an operating order requiring the Utility to benchmarks for procurement and perform the operational, dispatch, and authorizes the IOUs to procure electricity administrative functions for the DWR's allocated from the market subject to comparison contracts beginning on January 1, 2003. The with the CPUC-authorized benchmarks; or operating order, which applies prospectively, includes the DWR's proposed method of

• Upfront and achievable standards and criteria to determine the acceptability and calculating the amount of revenues that the Utility must pass-through to the DWR. As a eligibility for rate recovery of a proposed transaction and an expedited CPUC result, as of December 31, 2002, the Utility has pre-approval process for proposed accrued an additional $369 million (pre-tax) bilateral contracts to ensure compliance liability for pass-through revenues for electricity with the individual utility's procurement provided by the DWR to the Utility's customers.

plan.

In October 2002, the Utility filed a lawsuit in a SB 1976 provides that the CPUC may not California court asking the court to find that the approve the procurement plan if it finds the plan DWR's revenue requirements had not been contains features or mechanisms which would demonstrated to be "just and reasonable" (as impair restoration of the IOU's creditworthiness required by AB 1X) and lawful, and that the or would lead to a deterioration of the IOU's DWR had violated the procedural requirements of AB 1X in making its determination. The Utility creditworthiness. SB 1976 also indicates that procurement activities in compliance with an asked the court to order the DWR's revenue requirement determination be withdrawn as approved procurement plan will not be subject to after-the-fact reasonableness review. The invalid, and that the DWR be precluded from CPUC is permitted to establish a regulatory imposing its revenue requirements on the Utility and its customers until it has complied with the process to verify and ensure that each contract was administered in accordance with its terms law. No schedule has yet been set for consideration of the lawsuit.

104

and that contract disputes that arise are resolved Although the DWR retains legal and financial reasonably. responsibility for these contracts, the DWR has stated publicly that it intends to transfer full legal A central feature of the SB 1976 regulatory title of, and responsibility for, the DWR electricity framework is its direction to the CPUC to create contracts to the IOUs as soon as possible.

new electric procurement balancing accounts to However, SB 1976 does not contemplate a track and allow recovery of the differences transfer of title of the DWR contracts to the between recorded revenues and costs incurred lOUs. In addition, the operating order issued by under an approved procurement plan. The CPUC the CPUC in December 2002 implementing the must review the revenues and costs associated Utility's operational and scheduling responsibility with the Utility's electric procurement plan at with respect to the DWR allocated contracts least semi-annually and adjust rates or order specifies that the DWR will retain legal and refunds, as appropriate, to properly amortize the financial responsibility for the contracts and that balancing accounts. Until January 1, 2006, the the December 2002 order does not result in an CPUC must establish the schedule for amortizing assignment of the DWR allocated contracts. The the over-collections or under-collections in the Utility's proposed plan of reorganization electric procurement balancing accounts so that prohibits the Utility from accepting, directly or the aggregate over-collections or under- indirectly, assignment of legal or financial collections reflected in the accounts do not responsibility for the DWR contracts. There can exceed 5 percent of the IOU's actual recorded be no assurance that either the State of California generation revenues for the prior calendar year, or the CPUC will not seek to provide the DWR excluding revenues collected on behalf of the with authority to effect such a transfer of legal DWR. Mandatory semi-annual review and title in the future. The Utility has informed the adjustment of the balancing accounts will CPUC, the DWR and the State that the Utility continue until January 1, 2006, after which time would vigorously oppose any attempt to transfer the CPUC will conduct electric procurement the DWR allocated contracts to the Utility balancing account reviews and adjust retail without the Utility's consent.

ratemaking amortization schedules for the balancing accounts as the CPUC deems Chapter 11 Filing appropriate and in a manner consistent with the requirements of SB 1976 for timely recovery of On April 6, 2001, the Utility filed for relief under electricity procurement costs. Chapter 11 of the Bankruptcy Code. Under Chapter 11, the Utility is subject to the Allocation of DWR Electricfty to Customers jurisdiction of the Bankruptcy Court, however of the IOUs the Utility has control of its assets and is authorized to operate its business as a Consistent with applicable law and CPUC orders, debtor-in-possession. Subsidiaries of the Utility, since 2001, the Utility and the other California including PG&E Funding, LLC (which holds rate lOUs have acted as the billing and collection reduction bonds) and PG&E Holdings, LLC agents for the DWR's sales of its electricity to (which holds stock of the Utility), are not retail customers. In September 2002, the CPUC included in the Utility's Chapter 11 filing. PG&E issued a decision allocating the electricity Corporation, the Utility's parent, and PG&E NEG provided under existing DWR contracts to the have not filed for Chapter 11 and are not customers of the IOUs. This decision required included in the Utility's Chapter 11 filing. PG&E the Utility, along with the other IOUs, to begin Corporation, however, is a co-proponent of the performing all the day-to-day scheduling, Utility's proposed plan of reorganization.

dispatch, and administrative functions associated with the DWR contracts allocated to the IOUs' In connection with the Utility's Chapter 11 filing, portfolios by January 1, 2003. various parties have filed claims with the Bankruptcy Court. Through December 31, 2002, claims filed with the Bankruptcy Court totaled 105

approximately $49.4 billion. Of the $49.4 billion The balance of Liabilities Subject to Compromise of claims filed, claims for approximately increases and decreases due to a variety of

$25.5 billion have been disallowed by the factors. For example, disputed claims may be Bankruptcy Court due to objections submitted by resolved or the Bankruptcy Court may authorize the Utility or as a result of the claimants payment of certain claims.

withdrawing their claims from the Bankruptcy Court. Of the remaining $23.9 billion of filed The Bankruptcy Court has authorized the Utility claims, pursuant to the Plan and alternative plan to pay certain pre-petition claims and pre- and (discussed below), claims totaling approximately post-petition interest on certain claims prior to

$6.6 billion are expected to pass through the emerging from Chapter 11. Pursuant to bankruptcy proceeding and be determined in the Bankruptcy Court authorization, through appropriate court or other tribunal during the December 31, 2002, approximately $901 million bankruptcy proceeding or after it concludes. in principal and $60 million in interest had been paid to qualifying facilities (QFs). The The Utility intends to object to approximately Bankruptcy Court has also authorized the Utility

$4.3 billion of the remaining $23.9 billion of filed to pay all undisputed creditor claims that amount claims. These objections relate primarily to to $5,000 or less and undisputed mechanics' lien generator claims. Approximately $500 million of and reclamation claims. At December 31, 2002, the $23.9 billion of filed claims are subject to the majority of these payments had been made pending Utility objections. The Utility has and totaled approximately $10 million. Also recorded its estimate of all valid claims at pursuant to Bankruptcy Court authorization, the December 31, 2002, as $9.4 billion of Liabilities Utility has paid approximately $1.3 billion Subject to Compromise and $3.0 billion of through January 2, 2003, for pre- and Long-Term Debt. The Utility has paid certain post-petition interest on certain undisputed claims authorized by the Bankruptcy Court, as claims. The Utility also repaid advances and discussed below, and reduced the amount of interest on advances of approximately outstanding claims accordingly. In addition, since $25 million, through January 2, 2003, to banks its Chapter 11 filing, the Utility has accrued providing letters of credit backing pollution interest on all claims the Utility considers valid. control bonds. In addition, the Utility has paid This additional interest accrual is not included in approximately $79 million in refunds for the original $49.4 billion of claims filed. The customer deposits, reimbursements for work following schedule summarizes the activity of the performed by customers, and inspection fees for Utility's Liabilities Subject to Compromise from contracts related to gas and electric line the period of December 31, 2001 to extensions. A portion of these refunds, December 31, 2002. reimbursements, and inspection fees were paid (in billions) as part of the Utility's normal business Liabilities Subject to Compromise at December 31, operations, and were not included in claims filed 2001 .... $11.4 with the Bankruptcy Court.

Interest accrual for the year ended December 31, 2002 ............................. 0.3 Claims paid pursuant to Bankruptcy Court orders,, (1.4) As discussed above, the Bankruptcy Court has Claims and Interest authorized by the Bankruptcy Court to be paid (transferred to accounts payable authorized payment of certain claims. These or interest payable) ...... .............. (0.2) claims are therefore not included in the Reclassification of debt upon liquidation of trust $9.4 billion of Liabilities Subject to Compromise, holding solely Utility Subordinated Debentures (Noe 4) .......... ................. 0.3 however the Utility is paying interest on these Reversal of first quarter 2001 150 accrual .... .... (1.0) other claims at the various rates as described Liabilities Subject to Compromise at December 31, 2002 .$............................ 9.4 below. For certain claims, the Utility has Claims filed by PG&E Corporation and included in identified receivable balances owed to the Utility Liabilities Subject to Compromise ..... ...... (0.2) from the claimant. These receivable balances Liabilities Subject to Compromise at December 31, 2002, excluding claims payable to PG&E may be settled as offsets to claims filed by the Corporation ........ ................ $ 9.2 claimant, thereby reducing the amount of the 106

claim and the interest ultimately payable to the $333 million on this debt. At December 31, 2002, claimant. the Utility has $3 billion outstanding in pre-petition principal, secured debt. This debt is As specified in the Utility's proposed plan of classified as Long-Term Debt in the Consolidated reorganization (the Plan) described below, the Balance Sheets.

Utility has agreed to pay pre- and post-petition interest on Liabilities Subject to Compromise at The Bankruptcy Court has also authorized the rates set forth below, plus additional interest certain payments and actions necessary for the on certain claims as discussed below. Utility to continue its normal business operations while operating as a debtor-in-possession. For Amount Agreed Upon example, the Utility is authorized to pay Owed Rate (in milions) (per annum) employee wages and benefits, certain QFs, interest on secured debt, environmental Commercial Paper Claims ...... $ 873 7.466% remediation expenses, and expenditures related Floating Rate (Implied yield to property, plant and equipment. In addition, Notes ...... 1,240 7.583% of 7.690%) the Utility is authorized to refund certain Senior Notes ... 680 9.625% customer deposits, use certain bank accounts Medium-Term and cash collateral, and assume responsibility for Notes ...... 287 5.810% to 8.450%e Revolving Line of various hydroelectric contracts.

Credit Claims 938 8.000(%

Majority of QFs.. 97 5.000% ProposedPlan of Reorganization Other Claims . 5,276 Various itainies Sutfec to The Utility and PG&E Corporation have jointly Compomise at proposed a plan of reorganization, referred to as Decemner 31, the Plan, which would allow the Utility to 32 ....... $9,391 restructure its businesses and refinance the restructured businesses. The Plan is designed to Since the Plan did not become effective on or align the Utility's existing businesses under the before February 15, 2003, the interest rates for regulators that best match the business functions.

Commercial Paper Claims, Floating Rate Notes, Retail assets (natural gas and electricity Senior Notes, Medium-Term Notes, and distribution) would remain under the retail Revolving Line of Credit Claims have been regulator, the CPUC. The wholesale assets increased by 37.5 basis points, for periods on (electric transmission, interstate natural gas and after February 15, 2003. If the Plan does not transportation, and electric generation) would be become effective on or before September 15, placed under wholesale regulators, the FERC and 2003, the interest rates for these claims on and the Nuclear Regulatory Commission (NRC). After after such date will be increased by an additional this realignment, the retail-focused business 37.5 basis points. Finally, if the effective date would be a natural gas and electricity does not occur on or before March 15, 2004, the distribution company (Reorganized Utility),

interest rates for these claims on and after such representing approximately 70 percent of the date will be increased by an additional 37.5 basis book value of the Utility's assets.

points. For other claims, the Utility has recorded interest at the contractual or FERC-tariffed In contemplation of the Plan becoming effective, interest rate. When those rates do not apply, the the Utility has created three new limited liability Utility has recorded interest at the federal companies, the LLCs, which currently are owned judgment rate. by the Utility's wholly owned subsidiary, Newco Energy Corporation, or Newco. On the effective The Utility has received approval from the date of the Plan, the Utility would transfer Bankruptcy Court to make certain pre-petition substantially all the assets and liabilities primarily principal payments on secured debt that has related to the Utility's electricity generation matured and has, at December 31, 2002, paid business to Electric Generation LLC, or Gen; the 107

assets and liabilities primarily related to the to the Utility's electricity distribution Utility's electricity transmission business to system.

ETrans LLC, or ETrans; and the assets and liabilities primarily related to the Utility's natural

• The Reorganized Utility would rely on GTrans for the Reorganized Utility's gas transportation and storage business to natural gas transportation needs because GTrans LLC, or GTrans.

the facilities proposed to be transferred to GTrans are currently the only The Plan proposes that on the effective date, the transportation facilities directly connected Utility would distribute to PG&E Corporation all to the Utility's natural gas distribution of the outstanding common stock of Newco.

Each of ETrans, GTrans, and Gen would system. In addition, the Reorganized continue to be an indirect wholly owned Utility would rely on GTrans for a subsidiary of PG&E Corporation. Finally, on the substantial portion of the Reorganized Utility's natural gas storage requirements effective date of the Plan or as promptly thereafter as practicable, PG&E Corporation for at least 10 years under a transportation would distribute all the shares of the Utility's and storage services agreement between the Reorganized Utility and GTrans, common stock that it then holds to its existing though the Utility does have storage shareholders in a spin-off transaction. After the spin-off, the Reorganized Utility would be an options with third party providers to meet independent publicly held company. The a portion of their requirements.

common stock of the Reorganized Utility would

• The Reorganized Utility also would have be registered under federal securities laws and significant operating relationships with the would be freely tradable by the recipients on the LLCs covering a range of functions and effective date or as soon as practicable thereafter. services.

The Reorganized Utility would apply to list its common stock on the New York Stock Finally, the Reorganized Utility would continue Exchange. The Reorganized Utility would retain to rely on its natural gas transportation the name "Pacific Gas and Electric Company." agreement with PG&E GTN, for the transportation of western Canadian natural gas.

Although the Reorganized Utility would be legally separated from the LLCs, the Reorganized During 2002, the Utility undertook several Utility's operations would remain connected to initiatives to prepare for separation under the the operations of the LLCs after the effective date Plan. The Utility has spent approximately of the Plan. For example: $43 million through December 31, 2002, on these initiatives.

• The Reorganized Utility would rely on Gen for a significant portion of the The Plan proposes that allowed claims would be electricity the Reorganized Utility needs to satisfied by cash, long-term notes issued by the meet its electricity distribution customers' LLCs or a combination of cash and such notes.

demand during the 12-year term of a Each of ETrans, GTrans, and Gen would issue power purchase and sale agreement long-term notes to the Reorganized Utility and between the Reorganized Utility and Gen, the Reorganized Utility would then transfer the or the Gen power purchase and sale notes to certain holders of allowed claims. In agreement.

addition, each of the Reorganized Utility, ETrans,

. The Reorganized Utility would rely on GTrans, and Gen would issue "new money" ETrans for the Reorganized Utility's notes in registered public offerings. The LLCs electricity transmission needs because the would transfer the proceeds of the sale of the transmission lines proposed to be new money notes, less working capital reserves, transferred to ETrans are currently the to the Utility for payment of allowed claims. The only transmission lines directly connected Plan also would reinstate nearly $1.59 billion of 108

preferred stock and pollution control loan

• commit PG&E Corporation to contribute agreements. up to $700 million in cash to the Utility's capital from the issuance of equity or On February 19, 2003, Standard & Poor's (S&P), from other available sources, to the extent a major credit rating agency, announced that it necessary to satisfy the cash obligations of had re-affirmed its preliminary rating evaluation, the Utility in respect of allowed claims originally issued in January 2002, of the and required deposits into escrow for corporate credit ratings of, and the securities disputed clains, or to obtain investment proposed to be issued by the Reorganized Utility grade ratings for the debt to be issued by and the LLCs in connection with the the Reorganized Utility and the LLCs.

implementation of the Utility Plan. Subject to the satisfaction of various conditions, S&P stated that In addition to the amendments to the Plan, the approximately $8.5 billion of securities amendments to various filings at the FERC, and proposed to be issued by the Reorganized Utility possibly other regulatory agencies, will be and the LLCs, as well as their corporate credit required in order to implement the changes to ratings, would be capable of achieving the Plan.

investment grade ratings of at least BBB-. In order to satisfy some of the conditions specified The Plan provides that it will not become by S&P, on February 24, 2003, the Utility filed effective unless and until the following amendments to the Utility Plan with the conditions have been satisfied or waived:

Bankruptcy Court that, among other

• The effective date of the Plan shall be on modifications: or before May 30, 2003;

• permit the Reorganized Utility and the

• All actions, documents, and agreements LLCs to issue secured debt instead of necessary to implement the Plan shall unsecured debt, have been effected or executed;

• permit adjustments in the amount of debt

• PG&E Corporation and the Utility shall the Reorganized Utility and the LLCs have received all authorizations, consents, would issue so that additional new money regulatory approvals, rulings, letters, notes could be issued if additional cash is no-action letters, opinions, or documents required to satisfy allowed claims or to that are determined by PG&E Corporation deposit in escrow for disputed claims and and the Utility to be necessary to such debt can be issued while implement the Plan; maintaining investment grade ratings, or

• S&P and Moody's shall have established so that less debt could be issued in order investment-grade credit ratings for each of to obtain investment grade ratings or if the securities to be issued by the less cash is required to satisfy allowed Reorganized Utility, ETrans, GTrans, and claims and be deposited into escrow for Gen of not less than BBB- and Baa3, disputed claims, respectively;

• require Gen to establish a debt service

• The Plan shall not have been modified in reserve account and an operating reserve a material way since the confi-mation account, date; and

• under certain circumstances, permit an

• The registration statements pursuant to increase in the amount of cash creditors which the new securities will be issued receiving cash and notes will receive, shall have been declared effective by the SEC, the Reorganized Utility shall have

• permit the Utility's mortgage-backed pollution control bonds to be redeemed if consummated the sale of its new the Reorganized Utility issues secured securities to be sold under the Plan, and new money notes, and the new securities of each of ETrans, GTrans, and Gen shall have been priced 109

and the trade date with respect to each CPUC enter into a "reorganization agreement" shall have occurred. under which the CPUC promises to establish retail electric rates on an ongoing basis sufficient If one or more of the conditions described above for the Utility to achieve and maintain investment have not occurred or been waived by May 30. grade credit ratings and to recover in rates 2003, the confirmation order would be vacated. (1) the interest and dividends payable on, and The Utility's obligations with respect to claims the amortization and redemption of, the and equity interests would remain unchanged. securities to be issued under the alternative plan, and (2) certain recoverable costs (defined as the PG&E Corporation and the Utility contend that amounts the Utility is authorized by the CPUC to bankruptcy law expressly preempts state law in recover in retail electric rates in accordance with connection with the implementation of a plan of historic practice for all of its prudently incurred reorganization. The Bankruptcy Court rejected costs, including capital investment in property, this contention. PG&E Corporation and the plant and equipment, a return of capital and a Utility appealed the express preemption aspect return on capital and equity to be determined by of this decision to the U.S. District Court. The the CPUC from time to time in accordance with U.S. District Court reversed the Bankruptcy its past practices).

Court's ruling and remanded the case back to the Bankruptcy Court for further proceedings, ruling PG&E Corporation and the Utility believe the that the Bankruptcy Code expressly preempts alternative plan is not credible or confirmable.

"nonbankruptcy laws that would otherwise apply PG&E Corporation and the Utility do not believe to bar, among other things, transactions the alternative plan would restore the Utility to necessary to implement the reorganization plan." investment grade status if the alternative plan The U.S. District Court entered judgment on were to become effective. Additionally, PG&E September 19, 2002, and the CPUC and several Corporation and the Utility believe the alternative other parties thereafter initiated an appeal to the plan would violate applicable federal and state U.S. Court of Appeals for the Ninth Circuit, law.

which is pending.

ConfirmationHearings The CPUC'OCCsAlternative Plan of Reorganization Solicitation of creditor votes began on June 17, 2002, and concluded on August 12, 2002. On The CPUC and the OCC have jointly proposed September 9, 2002, an independent voting agent an alternative plan of reorganization for the filed the voting results with the Bankruptcy Utility that does not call for realignment of the Court. Nine of the ten voting classes under the Utility's existing businesses. The alternative plan Utility's proposed plan of reorganization instead provides for the continued regulation of approved the Plan. The alternative plan was all of the Utility's current operations by the approved by one of the eight voting classes CPUC. The alternative plan proposes to satisfy all under the alternative plan.

allowed creditor claims in full either through reinstatement or payment in cash, using a On November 6, 2002, the CPUC and the OCC combination of cash on hand and the proceeds filed an amended alternative plan and filed a from the issuance of $7.3 billion of new senior motion asking the Bankruptcy Court to authorize secured debt and the issuance of $1.5 billion of the resolicitation of creditor votes and new unsecured debt and preferred securities. preferences. The Bankruptcy Court heard oral The alternative plan proposes to establish a arguments on November 27, 2002. On

$1.75 billion regulatory asset, which would be February 6, 2003, the Bankruptcy Court issued amortized over ten years and would earn the full an order denying the CPUC's and the OCC's rate of return on rate base. request.

The CPUC/OCC Plan also provides that it would In determining whether to confirm either plan, not become effective until the Utility and the the Bankruptcy Court will consider creditor and 110

equity interests, plan feasibility, distributions to

• Significant decline in generation margins creditors and equity interests, and the financial (spark spreads) caused by excess supply viability of the reorganized entities. Various and reduced demand in most regions of parties have filed objections to confirmation of the United States; either or both plans. PG&E Corporation and the - Loss of confidence in energy companies Utility filed objections to the alternative plan due to increased scrutiny by regulators, stating their belief that the alternative plan is elected officials, and investors as a result neither feasible nor confirmable for the reasons of a string of financial reporting scandals; discussed above. The CPUC also filed an objection to the Plan. . Heightened scrutiny by credit rating agencies prompted by these market The trial on confirmation of the alternative plan changes and scandals which resulted in began on November 18, 2002. The trial on the lower credit ratings for many market Plan began on December 16, 2002, with participants; and objections common to both plans slated for trial

• Resulting significant financial distress and during the Plan trial. liquidity problems among market participants leading to numerous financial The Utility is unable to predict which plan, if restructurings and less market any, the Bankruptcy Court will confirm. If either participation.

plan is confirmed, implementation of the confirmed plan may be delayed due to appeals, PG&E NEG has been significantly impacted by CPUC actions or proceedings, or other regulatory these changes in 2002. New generation came hearings that could be required in connection online while the economic recession reduced with the regulatory approvals necessary to demand. This oversupply and reduced demand implement that plan, and other events. The resulted in low spark spreads (the net of power uncertainty regarding the outcome of the prices less fuel costs) and depressed operating bankruptcy proceeding and the related margins. These changes in the power industry uncertainty around the plan of reorganization have had a significant negative impact on the that is ultimately adopted and implemented will financial results and liquidity of PG&E NEG.

have a significant impact on the Utility's future liquidity and results of operations. The Utility is Before July 31, 2002, most of the various debt unable at this time to predict the outcome of its instruments of PG&E NEG and its affiliates bankruptcy case or the effect of the carried investment-grade credit ratings as reorganization process on the claims of the assigned by S&P and Moody's, two major credit Utility's creditors or the interests of the Utility's rating agencies. Since July 31, 2002, PG&E NEG's preferred shareholders. However, the Utility rated entities have been downgraded several believes, based on information presently times. The result of these downgrades had left all available to it, that cash and cash equivalents on of PG&E NEG's rated entities and debt hand at December 31, 2002, of $3.3 billion and instruments at below investment grade.

cash available from operations will provide sufficient liquidity to allow it to continue as a The downgrade of PG&E NEG's credit ratings going concern through 2003. impacts various guarantees and financial arrangements that require PG&E NEG to NOTE 3: PG&E NEG UQUIDITY MAITMIS maintain certain credit ratings by S&P and/or Moody's. PG&E NEG's counterparties have During 2002, adverse changes in the electric demanded that PG&E NEG provide additional power and gas utility industry and energy security for performance in the form of cash, markets affected PG&E Corporation, the Utility letters of credit, acceptable replacement and PG&E NEG business including: guarantees, or advanced funding of obligations.

Contractions and instability of wholesale Other counterparties continue to have the right electricity and energy commodity markets; to make such demands. If PG&E NEG fails to 111

provide this additional collateral within defined $431 million 364-day tranche of its Corporate cure periods, PG&E NEG may be in default Revolver. The amount outstanding under the under contractual terms. In addition to two-year tranche of the Corporate Revolver is agreements containing ratings triggers, other $273 million, the majority of which supports agreements allow counterparties to seek outstanding letters of credit. The default under additional security for performance whenever the Corporate Revolver also constitutes a cross-such counterparty becomes concerned about default under PG&E NEG's (outstanding)

PG&E NEG's or its subsidiaries' creditworthiness. (1) Senior Notes ($1 billion), (2) guarantee of the PG&E NEG's credit downgrade constrains its Turbine Revolver ($205 million), and (3) equity access to additional capital and triggers increases commitment guarantees for the GenHoldings in cost of indebtedness under many of its credit facility ($355 million), for the La Paloma outstanding debt arrangements. credit facility ($375 million) and for the Lake Road credit facility ($230 million). In addition, on The credit downgrade also impacted PG&E November 15, 2002, PG&E NEG failed to pay a NEG's and its subsidiaries' ability to service their $52 million interest payment due under the financial obligations by putting constraints on the Senior Notes.

ability to move cash from one subsidiary to another or to PG&E NEG itself. PG&E NEG's PG&E Corporation continues to provide subsidiaries must now independently determine, assistance to PG&E NEG, its subsidiaries and its in light of each company's financial situation, lenders in their negotiations to establish a whether any proposed dividend, distribution or restructuring of PG&E NEG's commitments.

intercompany loan is permitted and is in such However, if these negotiations prove subsidiary's interest. unsuccessful and if lenders exercise their default remedies or if the financial commitments are not PG&E NEG is currently in default under various restructured, PG&E NEG and certain of its recourse debt agreements and guaranteed equity subsidiaries may be compelled to seek protection commitments totaling approximately $2.9 billion. under or be forced into a proceeding under In addition, other PG&E NEG subsidiaries are in Chapter 11 of the Bankruptcy Code. Management default under various debt agreements totaling does not expect the liquidity constraints of PG&E approximately $2.5 billion, but this debt is non- NEG and its subsidiaries will affect the financial recourse to PG&E NEG. On November 14, 2002, condition of PG&E Corporation or the Utility.

PG&E NEG defaulted on the repayment of the 112

Debt in Default and Long-Term Debt The schedule below summarizes PG&E NEG's outstanding debt in default and long-term debts as of December 31, 2002, and 2001:

Outstanding (in millions) Maturity Interest Rates Balance December 31, 2002 2001 Debt in Default (1)

PG&E NEG, Inc. Senior Unsecured Notes 2011 10.375% $1,000 $1,000 PG&E NEG, Inc. Credit Facility - Tranche B (364 day) 11/14/02 Prime plus credit spread 431 330 PG&E NEG, Inc. Credit Facility - Tranche A (2-year facility with a $273 million total commitment) 8/23/03 Prime plus credit spread 42 Turbine and Equipment Facility 12/31/03 Prime plus credit spread 205 221 LIBOR plus credit GenHoldings Construction Facility Tranche A 12/5/03 spread 118 LIBOR plus credit GenHoldings Construction Facility Tranche B 12/5/03 spread 1,068 450 GenHoldings Swap Termination 50 Lake Road Construction Facility Tranche A 12/11/02 Prime plus credit spread 227 206 Lake Road Construction Facility Tranche B 12/11/02 Prime plus credit spread 219 198 Lake Road Construction Facility Tranche C Prime plus credit spread 13 Lake Road Working Capital Facility 12/09/03 Prime plus credit spread 23 Lake Road Swap Termination 12/11/02 61 La Paloma Construction Facility Tranche A 12/11/02 Prime plus credit spread 367 319 La Paloma Construction Facility Tranche B 12/11/02 Prime plus credit spread 291 251 La Paloma Construction Facility Tranche C 12/11/02 Prime plus credit spread 20 18 La Paloma Construction Facility 29 La Paloma Swap Termination 79 Subtotal 4,230 3,006 Long-Term Debt PG&E GTN Senior Unsecured Notes 2005 7. 100% 250 250 PG&E GTN Senior Unsecured Debentures 2025 7.80% 150 150 PG&E GTN Senior Unsecured Notes 2012 6.62% 100 Through PG&E GTN Medium Term Notes 2003 6.96% 6 39 LIBOR plus credit PG&E GTN Credit Facility 5/2/05 spread 58 85 LIBOR plus credit USGenNE Credit Facility 9/1/03 spread 75 75 LIBOR plus credit Plains End Construction Facility 9/6/06 spread 56 23 Principally LIBOR plus Other non-recourse project term loans Various credit spread 100 Mortgage loan payable 2010 CP rate + 6.07% 7 7 Other Various Various 20 17 Subtotal 722 746 Total Debt In default and Long-term debt $4,952 $3,752 Amounts classified as:

Debt in default $4,230 $ -

Long-term debt, classified as current 17 378 Long-term debt 630 3,299 Amount related to liabilities of operations held for sale, classified as current 75 75 Total Debt in default and Long-term debt $4,952 $3,752 fi Certain PG&E NEG long-tenm debt has been reclassified under debt in default above and has been classified as current liabilities in the accompanying Consolidated Balance Sheets. These instruments were not in default during 2001.

113

As of December 31, 2002, scheduled maturities PG&E NEG also has other revolving credit of PG&E NEG debt in default and long-term debt facilities held by subsidiaries. These facilities were as follows: relate specifically to funding requirements of these entities and are not available to PG&E (in millions)

NEG. Under the terms of the various revolving Three months ended March 31, 2003 $1,431 credit facilities, the credit spread component of Three months ended June 30, 2003 the interest rates and fees charged for Three months ended September 30, 2003 42 borrowings was increased as a result of PG&E Three months ended December 31, 2003 2,757 NEG's credit downgrades. PG&E NEG's credit Total debt in default $4,230 downgrades did not trigger any acceleration of 2003 92 payments due under these long-term debt 2004 3 arrangements.

2005 310 2006 52 2007 PG&E Gfl Credit Facility -On May 2, 2002, Thereafter 261 PG&E GTN entered into a three-year Total Long-term debt $ 722 $125 million revolving credit facility. At December 31, 2002, there was $58 million outstanding under this facility. The average PG&E NEG Senior UnsecuredNotes - On weighted interest rate on the amount outstanding May 22, 2001, PG&E NEG completed an offering at December 31, 2002 is approximately of $1 billion in senior unsecured notes (Senior 2.89 percent.

Notes) and received net proceeds of approximately $972 million after bond debt Turbine and Equipnwnt Facility -In discount and note issuance costs. May 2001, PG&E NEG established a revolving credit facility of up to $280 million to fund On November 15, 2002, PG&E NEG failed to pay turbine payments and equipment purchases a $52 million interest payment due on these associated with its generation facilities. The notes. At December 31, 2002, PG&E NEG has an average weighted interest rate on the amount outstanding interest payment due on these notes outstanding at December 31, 2002 is of $65 million. approximately 4.66 percent.

Credit Facilities-In August 2001, PG&E NEG USGenNE Credit Facility -In August 2001, arranged a $1.25 billion working capital and USGenNE entered into a credit and letter of letter of credit facility consisting of a $750 million credit facility that has a total commitment of tranche with a 364-day term and a $500 million $100 million of which $75 million have been tranche with a two-year term. On October 21, drawn upon and $13 million supports letters of 2002, the available commitments were reduced credit that have been issued and are outstanding to $431 million and $279 million, respectively. As at December 31, 2002. Total amounts outstanding of December 31, 2002, $431 million had been under this facility, including any accrued interest drawn against the 364-day revolving credit are included in Liabilities of operations held for facility and $42 million had been drawn against sale on the Consolidated Balance Sheets. See the two-year facility, in addition to $231 million Note 6 Discontinued Operations. The average of letters of credit issued under the two-year weighted interest rate on the amount outstanding facility. At December 31, 2002, PG&E NEG had is approximately 2.61 percent.

outstanding interest accrued on these facilities of

$6 million.

114

Genfloldings Construction Facility -In In connection with the lenders' waiver of various December 2001, PG&E NEG entered into a defaults and additional funding commitments,

$1.075 billion 5-year non-recourse credit facility, PG&E NEG has agreed to cooperate with any which increased to $1.46 billion on April 5, 2002, reasonable proposal by the lenders regarding for the GenHoldings 1, LLC, (GenHoldings) disposition of the equity in or assets of any or all portfolio of projects secured by the Millennium, of the PG&E NEG subsidiaries holding the Harquahala, Covert, and Athens projects. The Athens, Covert, Harquahala and Millennium facility was intended to be used to reimburse projects. The amended credit agreement provides PG&E NEG and lenders for a portion of the that an event of default will occur if the Athens, construction costs already incurred on these Covert, Harquahala and Millennium facilities are projects and to fund a portion of the balance of not transferred to the lenders or their designees the construction costs through completion. on or before March 31, 2003. Such a default would trigger lender remedies, including the GenHoldings has defaulted under its credit right to foreclose on the projects.

agreement by failing to make equity contributions to fund construction draws for the Under the waiver, PG&E NEG has re-affirmed its Athens, Harquahala, and Covert generating guarantee of GenHoldings' obligation to make projects. Through December 31, 2002, equity contributions to these projects of GenHoldings has contributed $833 million of approximately $355 million. Neither PG&E NEG equity to the projects. Although PG&E NEG has nor GenHoldings currently expects to have guaranteed GenHoldings' obligation to make sufficient funds to make this payment. The equity contributions, PG&E NEG has notified the requirement to pay $355 million will remain an GenHoldings lenders that it will not make further obligation of PG&E NEG that would survive the equity contributions on behalf of GenHoldings. transfer of the projects.

In November and December 2002, the lenders executed waivers and amendments to the credit Further, as a result of GenHoldings' failure to agreement under which they agreed to continue make required payments under the interest rate to waive until March 31, 2003, the default caused hedge contracts entered into by GenHoldings, by GenHoldings' failure to make equity the counterparties to such interest rate hedge contributions. In addition, certain of these contracts terminated the contracts during lenders agreed to increase their loan December 2002. Settlement amounts due by commitments to an amount sufficient to provide GenHoldings in connection with such terminated (1) the funds necessary to complete construction contracts are, in the aggregate, approximately of the Athens, Covert and Harquahala facilities; $49.8 million.

and (2) additional working capital facilities to enable each project, including Millennium, to Lake Road and La Paloma Construction timely pay for its fuel requirements and to Facilities -In September 1999 and March 2000, provide its own collateral to support natural gas Lake Road and La Paloma (respectively) entered pipeline capacity reservations and independent into Participation Agreements to finance the transmission system operator requirements. The construction of the two plants. In 2001, November and December 2002 increased loan subsequent to the issuance of the 1999 and 2000 commitments are senior to the original liens and financial statements, management determined rank equally with each other but are senior to that the assets and liabilities related to these amounts loaned through and including the leased facilities should have been consolidated.

October credit extension. As a result, on In November 2002 Lake Road and La Paloma November 25, 2002, the funding lenders paid defaulted on their obligations to pay interest and GenHoldings' then pending draw request of swap payments. In addition, as a result of PG&E approximately $75 million and on December 23, NEG's downgrade to below investment-grade by 2002, the funding lenders paid GenHoldings' both S&P and Moody's, PG&E NEG, as guarantor then pending draw request of approximately of certain debt obligations of Lake Road and La

$44 million. Paloma, became required to make equity 115

contributions to Lake Road and La Paloma of make the payments will remain an obligation of

$230 million and $375 million respectively. None PG&E NEG that would survive the transfer of the of PG&E NEG, Lake Road or La Paloma have projects.

sufficient funds to make these payments.

Further, as a result of the La Paloma and Lake As of December 4, 2002, PG&E NEG and certain Road subsidiaries' failure to make required subsidiaries entered into various agreements with payments under the interest rate hedge contracts the respective lenders for each of the Lake Road entered into by them, the counterparties to such and La Paloma generating projects providing for interest rate hedge contracts have terminated the (1) funding of construction costs required to contracts. Settlement amounts due from the Lake complete the La Paloma facility; and Road and La Paloma project subsidiaries in (2) additional working capital facilities to enable connection with such terminated contracts are, in each subsidiary to timely pay for its fuel the aggregate, approximately $61 million for requirements and to provide its own collateral to Lake Road and $79 million for La Paloma.

support natural gas pipeline capacity reservations and independent transmission system operator PG&E G7N Senior Unsecured Notes, requirements, as well as for general working Debentures and Medium-Term Notes capital purposes. Lenders extending new credit under these agreements have received liens on On May 31, 1995, PG&E GTN completed the sale the projects that are senior to the existing of $400 million of debt securities through a lenders' liens. These agreements provide, among $700 million shelf registration. PG&E GTN issued other things, that the failure to transfer the Lake $250 million of 7.10 percent 10-year senior Road and La Paloma projects to the respective unsecured notes due June 1, 2005, and lenders by June 9, 2003 will constitute a default $150 million of 7.80 percent 30-year senior under the agreements. The failure to transfer the unsecured debentures due June 1, 2025. The facilities would entitle the lenders to accelerate 10-year notes were issued at a discount to yield the new indebtedness and exercise other 7.11 percent and the 30-year debentures were remedies. issued at a discount to yield 7.95 percent. At December 31, 2002, the unamortized debt In consideration of the lenders' forebearance and discount balance for the notes and debentures additional funding, PG&E NEG had previously were $0.1 million and $2.0 million, respectively.

agreed to cooperate, and cause its subsidiaries to The 30-year debentures are callable after June 1, cooperate, with any reasonable proposal 2005, at the option of GTN. Both the senior regarding disposition of the ownership interests unsecured notes and the senior unsecured in and/or assets of the La Paloma project, on debentures were downgraded during 2002 to a terms and conditions satisfactory to the lenders credit rating of CCC from Standard and Poor's in their sole discretion. and B1 from Moody's Investors Service.

The La Paloma and Lake Road projects have On June 6, 2002, PG&E GTN issued $100 million been financed entirely with debt. PG&E NEG has of 6.62 percent Senior Notes due June 6, 2012.

guaranteed the repayment of a portion of the Proceeds were used to repay $90 million of debt project subsidiary debt in the approximate on its revolving credit facility, and the balance aggregate amounts of $374.5 million for La retained to meet general corporate needs.

Paloma and $230 million for Lake Road, which amounts represent the subsidiaries' equity In addition, during 1995, $70 million of medium-contribution in the projects. The lenders have term notes were issued at face values ranging accelerated the guaranteed portion of the debt from $1 million to $17 million. As at January 31, and made a payment demand under the PG&E 2003 the medium-term notes carry a credit rating NEG guarantee. Neither the PG&E NEG of CCC from Standard and Poor's and Bi from subsidiaries nor PG&E NEG have sufficient funds Moody's Investors Service. Medium-term notes to make these payments. The requirement to totalling $33 million in 2002 and $31 million in 116

2001 matured and were accordingly agreements limiting the right of any subsidiary of extinguished. The remaining notes mature during PG&E NEG to make payments to its 2003 and have an average interest rate of shareholders; and certain transactions with 6.96 percent. affiliates. Certain credit agreements also require that PG&E NEG maintain a minimum ratio of Plains End Construction Facility -In cash flow available for fixed charges to fixed September 2001, PG&E NEG established a facility charges and a maximum ratio of funded for $69.4 million. The debt facility was used to indebtedness to total capitalization.

fund the balance of construction costs for the Plains End project. The facility expires upon the Letters of Credit earlier of five years after commercial operations have been declared or September 2007. The In addition to outstanding balances under the average weighted interest rate on the amount above credit facilities PG&E NEG has outstanding is approximately 5.17 percent. commitments available under these facilities and other facilities to issue letters of credit.

Other long-term debt consists of non-recourse project financing associated with unregulated The following table lists the various facilities that generating facilities, premiums, and other loans. have the capacity to issue letters of credit:

Certain credit agreements contain, among other Leter of Credit restrictions, customary affirmative covenants, Letter of Outstanding representations and warranties and have cross- (in millions) Credit Dcember 31, Borrower Maturity Capacity 2002 default provisions with respect to PG&E NEG's PG&E NEG ...... 8/03 $231 $231 other obligations. The credit agreements also USGenNE ...... 8/03 25 13 contain certain negative covenants including PG&E Gen ...... 12/04 7 7 restrictions on the following: consolidations, PG&E ET ...... 9/03 19 19 mergers, sales of assets and investments; certain PG&E ET ...... 11/03 35 34 liens on the PG&E NEG's property or assets; incurrence of indebtedness; entering into 117

NOTE 4: DEBT FINANCING Debt in Default and Long-Term Debt Debt in default and long-term debt that matures in one year or more from the date of issuance consisted of the following:.

(in millions) Balance at December 31, 2002 2001 Debt In DefaulL,(1 PG&E NEG credit facilities In default Revolving credit facilities in default.................... $ 473 $ 330 PG&E NEG long-term debt in default Senior unsecured notes, 10.375%, due 2011 ................. $1,000 $1,000 Term loans, various, 2002-2003 ..................... 2,757 1,676 Total long-term debt in default ................... 3,757 2,676 Total Debt In Default ........................ $4,230 $3,006 Long-Term Debt, PG&E Corporation Lehman Loans due 2006, variable .................... S 720 $-

9.50% Convertible Subordinated Notes................... 280-General Electric and Lehman Loans due in 2003, variable............. - 1,000 Discount............................ (24) -(96)

Total long-term debt, net of current portion ................ 976 904 Utility First and refunding mortgage bonds:

Maturity Interest Rates 2003-2005 5.875% to 6.250% .................... 880 1,214 2006-2010 6.35% to 6.625% .................... 85 85 2011-2026 5.85% to 8.80%..................... 2.079 2,079 Principyal amounts outstanding..................... 3,044 3,378 Unamortized. discount net of premium .................. (24) (26)

Total mortgage bonds........................ 3,020 3,352 Less: current portion......................... 281 333 Total long-term debt, net of current portIon ................ 2,739 3,019 PG&E NEG Senior unsecured notes, 7.10%, due 2005.................. 250 250 Senior unsecured debentures, 7.80%, due 2025 ................ 150 150 Senior unsecured notes, 6.62%, due 2012.................. 100 -

Mediumn-te~rn notes, 6.83% to 6.96%, thru 2003 ................ 6 39 Term loans, various, 2006....................... 56 123 Amount outstanding under credit facilities.................. 133 160 Other long-term debts........................ 27 24 Sub-total .......................... 722 746 Less: current portion....................... 17 48 Amount related to liabilities of Operations held for sale, current........ 75 75 Total long-term debt, net of current portIon ................ 630 623 Total Long-Term Debt........................ $4,345 $4,546 Long-Term Debt Subject to Compromise-Utfility Senior notes, 9.63%, due 2005 ..................... 680 680 Pollution control loan agreements, variable rates, due 2016-2026........... 614 614 Pollution control loan agreement, 5.35% fixed rate, due 2016............ 200 200 Unsecured medium-term notes, 5.81% to 8.45%, due 2003-2014........... 287 287 Deferrable interest subordinated debentures, 7.9%, due 2025............ 300 -

Other Utility long-term debt...................... 19 20 Total Long-Term Debt Subject to Compromise................ $2,100 $1,801

'~Certain PG&E NEG long-term debt as of December 31, 2001 has been shown in the above schedule as debt in default above for comparative purposes. This long-term debt was not in default during 2001.

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PG&E Corporation In addition, the Credit Agreement provides for Payment-in-Kind (PIK) interest of 4 percent PG&E Corporation entered in a credit agreement commencing upon receipt of the funds. PIK (Original Credit Agreement) with General Electric interest is not paid in cash but rather added to Capital Corporation (GECC) and Lehman the principal amount of the loan at the start of Commercial Paper Inc. (LCPI) in 2001. During each interest period.

2002, PG&E Corporation negotiated new terms to the Original Credit Agreement. In August 2002, Except for an option agreement (Option PG&E Corporation made a voluntary prepayment Agreement), granting certain lenders options to of principal and interest totaling $607 million to purchase common stock of PG&E & NEG, in the GECC portion of the debt. As a result of the conjunction with the prior March 1, 2002, Credit prepayment, PG&E Corporation wrote off Agreement as amended (the Old Credit

$83 million of unamortized loan fees and Agreement), amounts under the Credit reversed $38 million of unamortized loan Agreement are senior unsubordinated obligations discount associated with unvested options, of PG&E Corporation.

netting to a $45 million charge to interest expense. In relation to the remainder of the loan, On September 3, 2002, General Electric Capital PG&E Corporation also recorded $70 million of Corporation (GECC) gave notice to PG&E debt extinguishment losses to interest expense, Corporation that it was exercising its right to sell as a result of new waiver extensions. (put) to PG&E Corporation its options representing 1.8 percent of PG&E NEG, which it On October 18, 2002, PG&E Corporation entered had acquired in connection with the Old Credit into a Second Amended and Restated Credit Agreement. Under the terms of the option Agreement (Credit Agreement) with Lehman agreement, PG&E Corporation and GECC entered Commercial Paper, Inc. (LCPI or, with other into an appraisal process to determine the value parties, the Lenders) with total principal amount of the PG&E NEG options. On October 30, 2002, of $720 million outstanding at December 31, before the completion of the appraisal process, 2002. The total principal amount includes GECC cancelled by giving notice of cancellation

$420 million previously retained under prior of its put notice, which was accepted by PG&E credit arrangements and $300 million Corporation. GECC no longer has the right to put representing new loans (New Loans), and these options to PG&E Corporation. On collectively referred to as the Loans. February 25, 2003, GECC exercised the options, which otherwise would have expired on The New Loans were released from escrow to March 1, 2003. Similar options representing PG&E Corporation on January 17, 2003, 1.2 percent of PG&E NEG must also be exercised concurrent with the payment of a funding fee of before March 1, 2003.

$9 million. The Loans are repayable in a single installment on September 2, 2006, unless repaid Under the Option Agreement discussed above, earlier in accordance with the Credit Agreement. certain lenders were granted warrants to purchase certain quantities of PG&E NEG shares.

The interest rate under the Credit Agreement is These warrants are marked to market on a Eurodollar Rate plus 10 percent, based upon monthly basis. In the third quarter of 2002, interest periods of one, two, three, or six PG&E Corporation recorded other income of months, as selected each period by PG&E $71 million, as a result of the change in market Corporation. Interest is payable quarterly or at value of the PG&E NEG warrants during that the end of the selected interest period, period. As discussed above, the appraisal process whichever is shorter. On January 17, 2003, PG&E to determine the value of PG&E NEG was not Corporation paid a first interest payment of completed. If it is determined that PG&E NEG's

$13 million and elected an initial interest period value is greater than the value currently reflected of six months. in the mark-to market accounting, PG&E 119

Corporation would be required to incur a charge entitled to accelerate and declare the Loans to earnings as a result of the increased valuation. immediately due and payable.

Security The Credit Agreement requires mandatory prepayments with the net cash proceeds from The Loans are secured by a first priority security incurrence of additional indebtedness, issuance interest in the common stock of PG&E NEG and or sale of equity by PG&E Corporation or the the common stock of the Utility, along with Utility, sale of certain assets by PG&E substantially all other assets of PG&E Corporation, the Utility, or PG&E NEG; the Corporation. receipt of condemnation or insurance proceeds, and distributions or dividends paid to PG&E Otber Terms Corporation or PG&E NEG.

Under the terms of the Credit Agreement, PG&E Upon mandatory prepayment, PG&E Corporation Corporation is required to make an offer to must pay a prepayment fee calculated depending repay the Loans (including prepayment fees) upon when the prepayment occurred.

under various circumstances, which include a change in control of PG&E Corporation and a PG&E Corporation Warrants spin-off of the Utility in connection with a plan of reorganization. In connection with the Credit Agreement, PG&E Corporation also issued to the Lenders warrants As required by the Credit Agreement, PG&E to purchase 2,658,268 shares of common stock Corporation retained an interest reserve of of PG&E Corporation, at an exercise price of

$76 million as of December 31, 2002, and upon $0.01 per share. These warrants expire on receipt of the New Loans placed an additional September 2, 2007, and are generally exercisable

$54 million into such interest reserve. except when by their exercise the holder becomes, and has the intention to remain, the Restrictions single largest common shareholder.

The Credit Agreement contains limitations, The fair market value of these warrants was among other restrictions, on the ability of PG&E estimated at the date of grant and recorded as a Corporation and certain of its subsidiaries to discount to long-term debt. At December 31, grant liens, consolidate, merge, purchase or sell 2002, the discount was $24 million, net of assets, declare or pay dividends, incur accumulated discount amortization of $1 million.

indebtedness, or make advances, loans, and investments. In connection with the prior June 25'h Amended and Restated Credit Agreement, PG&E However, PG&E Corporation is permitted to Corporation issued warrants to the lenders to dispose of PG&E NEG assets under certain purchase 2,397,541 shares of common stock of circumstances. Any proceeds to PG&E PG&E Corporation, at an exercise price of $0.01 Corporation from such permitted sales must be per share and with terms similar to the warrants applied to prepay the Loans. described above. The unamortized discount related to these warrants and other deferred Events of Default and Mandatory financing costs were charged to interest expense Prepayments upon the voluntary repayment of $600 million principal and interest of approximately The Credit Agreement contains certain events of $6.7 million in August 2002.

default, including PG&E Corporation's failure to pay any indebtedness of $100 million or more. PG&E Corporation has agreed to provide, Upon an event of default, the Lenders are following consummation of a plan of reorganization of the Utility, registration rights in 120

connection with the shares issuable upon retirement of the bonds. While in bankruptcy, exercise of these warrants. the Utility is prohibited from making payments on the Mortgage Bonds, without permission from Use of Proceeds the Bankruptcy Court. The Bankruptcy Court approved the payment of $333 million of PG&E Corporation will use the net proceeds of mortgage bonds maturing in March 2002 and has the New Loans, net of various interest reserve also approved the payment of interest in requirements, to fund corporate working capital accordance with the terms of the bonds.

and for general corporate purposes.

Included in the total mortgage bonds outstanding Convertible SubordinatedNotes at December 31, 2002, and 2001, are

$345 million of bonds held in trust for the On June 25, 2002, PG&E Corporation issued California Pollution Control Financing Authority 7.50 percent Convertible Subordinated Notes (the (CPCFA) with interest rates ranging from Notes) due 2007 in the aggregate principal 5.85 percent to 6.63 percent and maturity dates amount of $280 million. The Notes may be ranging from 2009 to 2023. In addition to these converted by the holders into 18,558,655 shares bonds, the Utility holds long-term pollution of the common stock of PG&E Corporation. control loan agreements with the CPCFA as described below.

Concurrent with the October 18, 2002, financing described above, the Note Indenture was Senior Notes -In November 2000, the Utility amended as follows: issued $680 million of five-year senior notes with an interest rate of 7.38 percent. The Utility used

• The cross default provisions related to the net proceeds to repay short-term borrowings PG&E NEG and its subsidiaries was incurred to finance scheduled payments due to deleted; the PX for August 2000 power purchases and for

• The interest rate on the Notes increased other general corporate purposes. These notes to 9.50 percent from 7.50 percent; contained interest rate adjustments dependent upon the Utility's unsecured debt ratings.

• The maturity of the Notes was extended to June 30, 2010, from June 30, 2007; and As a result of the Utility's credit rating

• PG&E Corporation provided the holders downgrades, there was an interest rate of the Notes with a one-time right to adjustment of 1.75 percent on the $680 million require PG&E Corporation to repurchase senior notes. In addition, there was an interest the Notes on June 30, 2007, at a purchase premium penalty of 0.5 percent imposed on the price equal to the principal amount plus senior notes due to the Utility's inability to make accrued and unpaid interest (including a public offering on April 30, 2001. Accordingly, any liquidated damages and pass-through the rate increased to 9.63 percent from dividends, if any). 7.38 percent effective November 1, 2001. In 2001, the Utility's bankruptcy filing and failure to Utility make payments on the senior notes were events of default. The senior notes have been classified First and Refunding Mortgage Bonds -First as Liabilities Subject to Compromise in the and refunding mortgage bonds are issued in Consolidated Balance Sheets at December 31, series and bear annual interest rates ranging 2002, and 2001.

from 5.85 percent to 8.80 percent. All real properties and substantially all personal Pollution Control Loan Agreements -

properties of the Utility are subject to the lien of Pollution control loan agreements from the the mortgage, and the Utility is required to make CPCFA totaled $814 million at December 31, semi-annual sinking fund payments for the 2002, and 2001.

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Interest rates on $614 million of the loans are Debentures (QUIDS) due 2025 issued by the variable. For 2002, the variable interest rates Utility with a value of $309 million at maturity.

ranged from 1.25 percent to 1.78 percent. These loans are subject to redemption by the holder On March 16, 2001, the Utility postponed under certain circumstances. They were secured quarterly interest payments on the QUIDS until primarily by irrevocable letters of credit (LOC) further notice in accordance with the bond's from certain banks, which based on terms terms. The corresponding quarterly payments on negotiated in 2002, mature in 2003 through 2004. the QUIPS, due on April 2, 2001, were similarly On March 1, 2001, a $200 million loan was postponed.

converted to a fixed rate obligation with an interest rate of 5.35 percent. Quarterly interest payments may be postponed up to 20 consecutive quarters under the terms of In April and May 2001, four loans totaling the bond agreement. According to the bond's

$454 million were accelerated and the banks terms, investors earn interest on the unpaid paid the amounts due under the LOCs. In the distributions at the rate of 7.90 percent. Upon meantime, the Utility was unable to make liquidation or dissolution of the Utility, holders interest payments due to the bankruptcy filing. of the QUIPS would be entitled to the liquidation preference of $25 per share plus all accrued and This resulted in like obligations from the Utility unpaid interest thereon to the date of payment.

to the banks. Amounts outstanding at December 31, 2002, and 2001, under the As discussed in Note 2, on March 27, 2002, the pollution control agreements were classified as Bankruptcy Court issued an order authorizing the Liabilities Subject to Compromise in the Utility to pay pre- and post-petition interest to Consolidated Balance Sheets at December 31, holders of certain undisputed claims, including 2002 and 2001. QUIPS, within ten business days after Bankruptcy Court approval of the Utility's Medium-Term Notes -The Utility has disclosure statement.

outstanding $287 million of medium-term notes due from 2002 to 2014 with interest rates ranging The disclosure statement was approved on from 5.81 percent to 8.45 percent, which are also April 24, 2002. On May 6, 2002, the Utility made in default. The outstanding principal amounts at payments to holders of QUIPS representing December 31, 2002, and 2001, were classified as interest accrued through February 28, 2002, and Liabilities Subject to Compromise in the on March 31, 2002, the Utility made an accompanying financial statements. additional interest payment for the one month ended March 31, 2002. On July 1, 2002, the 7.90 Percent Deferrable Interest Subordinate Utility made an interest payment for the three Debentures months ended June 30, 2002, and since then has continued to make quarterly interest payments as On November 28, 1995, PG&E Capital I (Trust), a scheduled.

wholly owned subsidiary of the Utility, issued 12 million shares of 7.90 percent Cumulative On April 12, 2001, Bank One, N.A., as Quarterly Income Preferred Securities (QUIPS), successor-in-interest to The First National Bank with a total liquidation value of $300 million. of Chicago (Property Trustee), gave notice that Concurrent with the issuance of the QUIPS, the an event of default exists under the Trust Trust issued to the Utility 371,135 shares of Agreement due to the Utility's filing for Chapter common securities with a total liquidation value 11 on April 6, 2001 (see Note 2). As a result of of $9 million. The Trust in turn used the net the event of default, the Trust Agreement proceeds from the QUIPS offering and issuance required the Trust to be liquidated by the trustee of the common stock securities to purchase by distributing the QUIDS, after satisfaction of 7.90 percent Deferrable Interest Subordinated liabilities to creditors of the Trust, to the holders of QUIPS. Pursuant to the Trustee's notice dated 122

April 24, 2002, the Trust was liquidated on QUIPS are reflected as "Mandatory Redeemable May 24, 2002. Upon liquidation of the Trust, the Preferred Securities of Trust Holding Solely former holders of QUIPS received a like amount Utility Subordinated Debentures" on PG&E of QUIDS. The terms and interest payments of Corporation's and the Utility's Consolidated the QUIDS correspond to the terms and interest Balance Sheets at December 31, 2001.

payments of the QUIPS.

PG&E NEG The QUIDS are included in financing debt classified as Liabilities Subject to Compromise on See Note 3 PG&E Liquidity Matters for PG&E Corporation's and Utility's Consolidated discussions related to PG&E NEG's debt in Balance Sheets at December 31, 2002. The default and long-term debt.

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Repayment Schedule At December 31, 2002, PG&E Corporation's combined aggregate amounts of maturing long-term debt are reflected in the table below:

(dollars In millions)

Expected maUrity date 2003 2004 2005 2006 2007 Thereafter Total PG&E Corporation")

Long-term debt:

Fixed rate obligations (9.50%

Convertible Subordinated Notes) ................ $ - $ - $ - $ - $ - $ 280 $ 280 Average interest rate ....... 9.50% 9.509/o Variable rate obligation'2 ) .... - - - 842 842 Utility:

Long-term debt:

Liabilities not subject to compromise:

Fixed rate obligations....... 281 310 290 - - 2,139 3,020 Average interest rate ....... 6.25% 6.25% 5.88%o - - 7.25% 6.92%

Liabilities subject to compromise:

Fixed rate obligations(3) ..... 173 54 696 1 1 261 1,186 Average interest rate ....... 7.40% 7.51% 9.56% 9.45% 9.45% 5.95% 8.35%

7.90 Percent Deferrable Interest Subordinated Debentures ............ _ _ - 300 300 Variable rate obligationst4).... 349 265 614 Rate reductions bonds ........ 290 290 290 290 290 _ 1,450 Average interest rate ....... 6.36% 6.42% 6.42%/6 6.44% 6.48% _0/0 6.42%

PG&E NEG-Long-term debt:

Fixed rate obligations ....... 6 250 250 506 Variable rate obligations ..... 86 3 60 52 4 11 216 Average interest rate ....... 6.41% 6.57% 6.92% 7.33% 7.31% 7.100% 6.95%

Total .................... $1,185 $ 922 $1,586 $1,185 $ 295 $3,241 $8,414

(" Certain PG&E NEG Long-term debt has been reclassified under Long-term debt in default and has been reclassified as a current liability in the accompanying Consolidated Balance Sheets. The maturity of such debt in default is disclosed in Note 3 PG&E NEG Liquidity Matters.

(12 $720 million outstanding at December 31, 2002, with 4 percent interest compounded yields value of $842 million at maturity.

(3' $132 million out of the 2003 repayment amount matured in 2002 and 2001, and was unpaid.

(" The expected maturity dates for pollution control loan agreements with variable interest rates are based on the maturity dates of the letters of credit securing the loans.

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Credit Facilities and Short-Term Borrowings a $1 billion five-year revolving credit facility.

This facility was used to support the Utility's The following table summarizes PG&E commercial paper program and other liquidity Corporation's lines of credit: requirements. Non-payment of matured commercial paper in excess of $100 million in (in millions) December 31, 2001 constituted an event of default under the 2002 2001 credit facility and consequently the bank Credit Facilities Subject to terminated its outstanding commitment. The Compromise: outstanding balance is classified as Liabilities Utility 5-year Revolving Credit Facility .... $ 938 $ 938 Subject to Compromise on the December 31, 2002, and 2001, Consolidated Balance Sheets.

Total UIncs of Credit Subject to Compromise ................ 938 938 Short-Term Borrowings Subject to CommercialPaper-The total amount of Compromise: commercial paper outstanding at December 31, Utility 2002, and 2001, was $873 million. The Utility has Bank Borrowings - Letters of Credit been in default on its commercial paper for Accelerated Pollution Control Agreements ............... 454 454 obligations since January 17, 2001. The weighted Floating Rate Notes ........... 1,240 1,240 average interest rate on the Utility's commercial Cormmercial Paper ............ 873 873 paper obligation as of December 31, 2002, and Total Short-Term Borrowings Subject 2001, was 7.47 percent.

to Compromise .............. 2,567 2,567 Total Credit Facilities and Short-Term Floating Rate Notes -The Utility issued a total Borrowings Subject to Compromise $3.505 $3,505 of $1,240 million of 364-day floating rate notes in November 2000, with interest payable quarterly.

The total amount outstanding on the Utility's These notes were not paid on the maturity date credit facilities was $938 million at December 31, of November 30, 2001. Non-payment of the 2002, and 2001. The total amount outstanding on floating rate notes was an event of default, the Utility's short-term borrowings was entitling the floating rate note trustee to

$2,567 million at December 31, 2002, and 2001. accelerate the repayment of these notes.

Due to the Utility's bankruptcy filing (see However, the Utility is prohibited from paying Note 2), both have been classified as Liabilities liabilities incurred prior to its bankruptcy filing Subject to Compromise in the table above and without Bankruptcy Court approval.

on the Consolidated Balance Sheets for 2002 and 2001. Bank Borrowing -Letters of Creditfor Accelerated Pollution Control Bonds - As The weighted average interest rate on the short- previously discussed in April and May 2001, four term borrowings subject to compromise as of pollution control loan agreements totaling December 31, 2002, and 2001, was 7.47 percent $454 million were accelerated by the note and 7.53 percent. holders. These accelerations were funded by various banks under letter of credit agreements Utility resulting in similar obligations from the Utility to the banks.

Credit Facilities -At December 31, 2002, and 2001, the Utility had $938 million outstanding on 125

PG&E NEG Funding are not available to creditors of the Utility or PG&E Corporation, and the transition See Note 3 PG&E Liquidity Matters for property is not legally an asset of the Utility or discussions related to PG&E NEG's credit PG&E Corporation.

facilities and short-term borrowings.

NOTE 6: DISCONTINUED OPERATIONS NOTE 5: RATE REDUCTION BONDS Discontinued Operations and Assets Held In December 1997, PG&E Funding LLC for Sale (Funding), a limited liability corporation wholly owned by and consolidated with the Utility, USGen New England- In September 1998, issued $2.9 billion of rate reduction bonds. The USGen New England, Inc. (USGenNE) acquired proceeds of the rate reduction bonds were used the non-nuclear generating assets of the New by PG&E Funding LLC to purchase from the England Electric System (NEES) for Utility the right, known as "transition property," approximately $1.8 billion. These assets to be paid a specified amount from a included:

non-bypassable charge levied on residential and

• 2,344 megawatts (MW) of coal and oil small commercial customers (Fixed Transition fired power plants in Massachusetts; Amount (FTA) charges). FTA charges are authorized by the CPUC pursuant to state

• 1,166 MW of hydroelectric facilities in legislation and will be paid by residential and New Hampshire, Vermont, and small commercial customers until the rate Massachusetts; reduction bonds are fully retired. FTA charges

• 495 MW of gas-fired power plants in are collected by the Utility and remitted to Rhode Island; Funding based on a transition property servicing agreement. On January 4, 2001, S&P lowered the

• Above market power purchase Utility's short-term credit rating to A-3, and on agreements with support payments January 5, 2001, Moody's lowered the Utility's provided by NEES for the first nine years; short-term credit rating to P-3. As a result, on

• Gas pipeline transportation contracts; and January 8, 2001, the Utility was required under the transition property servicing agreement to

• Transition wholesale load contracts begin remitting to Funding on a daily basis FTA known as Standard Offer Agreements.

charges paid by ratepayers, as opposed to once a month, as had previously been required. Consistent with its previously announced strategy to dispose of certain merchant assets, in The rate reduction bonds have maturity dates December 2002, the Board of Directors of PG&E ranging from 2003 to 2007, and bear interest at Corporation approved management's plan for the rates ranging from 6.36 percent to 6.48 percent. proposed sale of USGenNE.

The bonds are secured solely by the transition property and there is no recourse to the Utility Under the provisions of SFAS No. 144, USGenNE or PG&E Corporation. is accounted for as an asset held for sale at December 31, 2002. This requires that the asset The total amount of rate reduction bonds be recorded at the lower of fair value, less costs principal outstanding was $1,450 million at to sell or book value. Based on the current December 31, 2002, and $1,740 million at estimated fair value of a sale of USGenNE, PG&E December 31, 2001. The scheduled principal NEG recorded a pre-tax loss of $1.1 billion, with payments on the rate reduction bonds for the no tax benefits associated with the loss, in the years 2003 through 2007 are $290 million for fourth quarter of 2002. It is anticipated that the each year. While Funding is a wholly owned sale of USGenNE assets will occur during 2003.

consolidated subsidiary of the Utility, Funding is This loss on sale as well as the operating results legally separate from the Utility. The assets of from USGenNE is being reported as discontinued 126

operations in the Consolidated Financial December 31, 2002. This requires that the asset Statements of PG&E Corporation at be recorded at the lower of fair value, less costs December 31, 2002. to sell or book value. Based upon the current estimated proceeds from the sale of Mountain Mountain View - On September 17 and 28, View, PG&E NEG will record an immaterial gain 2001, PG&E NEG purchased Mountain View in the first quarter of 2003.

Power Partners, LLC and Mountain View Power Partners II, LLC, respectively (collectively referred The operating results from Mountain View are to as Mountain View). The two companies were reported as discontinued operations in the merged on October 1, 2002. Consolidated Financial Statements of PG&E Corporation at December 31, 2002.

These companies own 44 and 22 MW wind energy projects, respectively, near Palm Springs, ET Canada - In December 2002, the proposed California. PG&E NEG contracted with SeaWest sale of PG&E Energy Trading Canada for the operation and maintenance of the wind Corporation (ET Canada) to Seminole Gas units. Total consideration for these two Company Limited was approved. Based upon the companies was $92 million. The power is sold to sales price, PG&E Energy Trading Holdings the DWR under a 10-year contract. Corporation, the direct owner of the shares of ET Canada recorded a $25 million pre-tax loss, with In December 2002, the Board of Directors of no tax benefits associated with the loss, on the PG&E Corporation approved the sale of disposition of ET Canada. The transaction is Mountain View. On December 18, 2002, a anticipated to close by the end of February or subsidiary of PG&E NEG entered into an early March, 2003. Under the provisions of SFAS agreement to sell Mountain View to Centennial No. 144, the assets and liabilities of ET Canada Power, Inc. for $102 million. have been classified as assets held for sale and reflected as discontinued operations in the Under the provisions of SFAS No. 144, Mountain Consolidated Financial Statements of PG&E View is accounted for as an asset held for sale at Corporation at December 31, 2002.

127

The following table reflects the operating results of the combined USGenNE, Mountain View, and ET Canada before reclassification to discontinued operations:

(in millions) Year ended December 31, 2002 2001 2000 Operating Revenues .................. $1,289 $943 $905 Operating Expenses Cost of commodity sales and fuel ........ . . . . . . .. 993 486 483 Operations, maintenance, and management. . . . . . . .. 243 246 236 Depreciation and amortization .......... . . . . . . .. 71 66 64 Other operating expenses .............. . . . . . . .. 1 Total operating expense ............... 1,308 798 783 Operating Income (Loss) .............. . . . . . . .. (19) 145 122 Interest income ..................... . . . . . . .. 46 46 52 Interest expense .................... . . . . . . . (2) (4)

Other income (expense), net ........... . . . . . . . (11) (7)

Income Before Income Taxes .............................. 14 180 174 Income tax expense................................... 3 73 75 Earnings from USGenNE, Mountain View, and ET Canada classified as Discontinued Operations ............................. $ 11 $107 $ 99 The following table reflects the components of assets and liabilities of Operations held for sale of USGenNE, Mountain View, and ET Canada before reclassification to discontinued operations:

(in millions) December 31, 2002 2001 ASSETS Current Assets Cash and cash equivalents ......................................... $ 32 $ 66 Accounts receivable-trade ......................................... 300 398 Inventory ..................................................... 82 79 Price risk management ............................................ 196 187 Prepaid expenses, deposits and other ................................. 97 14 Total current assets held for sale ................................ 707 744 Property, Plant and Equipment Total property, plant and equipment .................................. 799 1,906 Accumulated depreciation ......................................... (285) (216)

Net property, plant and equipment (1)............................. 514 1,690 Other Noncurrent Assets Long-term receivables (2 ....................................... 319 455 Intangible assets, net of accumulated amortization of $37 million and $28 million 20 29 Price risk management. ...................................... 30 60 Other ........................................................ 33 20 Total noncurrent assets held for sale ............................. 916 2,254 TOTAL ASSETS HELD FOR SALE ..................................... $1,623 $2,998 128

(in miollons) December 31, 2002 2001 LIABILIIES Current Llabilities Long-term debt, classified as current .................................. $ 75 $

Accounts payable and accrued expenses ............................... 207 307 Price risk management ............................................ 331 141 Out-of-market contractual obligations (3) ............................... 86 116 Other ........................................................ _ 6 Total current liabilities of operations held for sale ................... 699 570 Noncurrent Liabilities Long-term debt ................................................. - 75 Deferred income taxes ............................................ - 187 Price risk management ............................................ 272 51 Out-of-market contractual obligations (3) ............................... 501 683 Other noncurrent liabilities and deferred credit .......................... 20 6 Total noncurrent liabilities of operations held for sale ................ 793 1,002 TOTAL LUBILMIES OF OPERATIONS HELD FOR SALE .................... 1,492 1,572 NET ASSETS HELD FOR SALE ....................................... $ 131 $1,426 (1) Includes impairment charges made against property, plant and equipment as further discussed in Note 7 Impairments, Write-offs, and Other Charges (2) Long-Term Receivable - USGenNE receives payments from a wholly owned subsidiary of NEES, related to the assumption by USGenNE in September 1998 of power supply agreements, which are payable monthly through January 2008. The long-term receivahles are valued at the present value of the scheduled payments using a discount rate chat reflects NEES' credit rating on the date of acquisition.

(3) Out-of-Market Contractual Obligations - Commitments contained in the underlying Power Purchase Agreements (PPAs), gas commodity and transportation agreements (collectively, the "Gas Agreements"), and Standard Offer Agreements, acquired by USGenNE in September 1998, were recorded at fair value, based on management's estimate of either or both the gas commodity and gas transportation markets and electric markets over the life of the underlying contracts, discounted at a rate commensurate with the risks associated with such contracts. Standard Offer Agreements reflect a commitment to supply electric capacity and energy necessary for certain NEES affiliates to meet their obligations to supply fixed-rate service. PPAs and Gas Agreements are amortized on a straight-line basis over their specific lives. The Standard Offer Agreements are amortized using an accelerated method since the decline in value is greater in earlier years due to increasing contract pricing terms designed to reduce demand for supply service over time.

DisconitinuedOperations of Energy transactions related to the disposal of the energy Services - In December 1999, PG&E commodity portion of PG&E ES for $20 million, Corporation's Board of Directors approved a plus net working capital of approximately plan to dispose of PG&E Energy Services (PG&E $65 million, for a total of $85 million. In ES), its wholly owned subsidiary, through a sale. addition, a portion of the PG&E ES business and The disposal has been accounted for as a assets was sold on July 21, 2000, for a total discontinued operation and PG&E NEG's consideration of $18 million.

investment in PG&E ES was written down to its estimated net realizable value. In addition, PG&E For the year ended December 31, 2000, an NEG provided a reserve for anticipated losses additional loss of $40 million, which includes an through the date of sale. In 2000, $31 million income tax benefit of $36 million, was recorded (net of taxes) of actual operating losses were as actual losses in connection with the disposal, charged against the reserve. During the second which exceeded the original 1999 estimate. The quarter of 2000, PG&E NEG finalized the principal reason for the additional loss was due 129

to the mix of assets, and the structure and timing Impairment of GenHoldings I LLC Projects:

of the actual sales agreements, as opposed to the GenHoldings, a subsidiary of PG&E NEG, is one reflected in the initial provision established obligated under its credit facility to make equity in 1999. In addition, the worsening energy contributions to fund construction of the situation in California also contributed to the Harquahala, Covert and Athens generating actual loss incurred. projects. This credit facility is secured by these projects in addition to the Millennium generating NOTE 7: IMPAIRENTS, WRPTE-OFFS AND facility. GenHoldings defaulted under its credit OTHER CHARGES agreement in October 2002 by failing to make equity contributions to fund construction draws Impairments and Write-Offs for the Athens, Harquahala and Covert generating projects. Although PG&E NEG has The following is a summary of impairments and guaranteed GenHoldings' obligation to make write-offs incurred by PG&E NEG in continuing equity contributions of up to $355 million, PG&E operations: NEG notified the GenHoldings' lenders that it Quater would not make further equity contributions on ended Year ended behalf of GenHoldings. In November and December 31, December 31, December 2002, the lenders executed waivers (in millons) 2002 2002 and amendments to the credit agreement under Assets to be Transferred which they agreed to continue to waive until to Lenders:

GenHoldings projects. 1,147 $1,147 March 31, 2003, the default caused by Lake Road and La GenHoldings' failure to make equity Paloma projects ... 452 452 contributions. In addition, certain of these Assets to he Abandoned: lenders have agreed to increase their loan Impairment of Mantua commitments to an amount sufficient to provide Creek project .... 279 Impairment of (1) the funds necessary to complete construction Kentucky Hydro of the Athens, Covert and Harquahala facilities; project ........ 18 and (2) additional working capital facilities to Impairment of Turbines and Other enable each project, including Millennium, to Related Equipment timely pay for its fuel requirements and to costs ......... 30 provide its own collateral to support natural gas Impairment of Project Development Costs 57 pipeline capacity reservations and independent transmission operator requirements. The Other Impairments, write-offs, and November and December increased loan charges: commitments are rank equally with each other Termination of but are senior to amounts loaned through and Interest Rate Swaps in Lake Road, La including the October credit extension.

Paloma, and GenHoldings In consideration of the lenders' forbearance and projects .... 189 Impairment of 189 additional funding, PG&E NEG and GenHoldings Dispersed have agreed to cooperate with any reasonable Generation Assets 88 118 proposal by the lenders regarding disposition of Impairment of Goodwill ....... 95 the equity in or assets of any or all of the Impairment of GenHoldings subsidiaries holding the Athens, Southaven loan ... 74 74 Covert, Harquahala, and Millennium projects in Impairment of Prepaid Rents related to connection with the restructuring of PG&E NEG's Attala lease ..... 43 43 and its subsidiaries' financial commitments to Total Impairments, such lenders. The amended credit agreement write-offs and other provides that an event of default will occur if the charges ......... 2,377 $2-,767 Athens, Covert, Harquahala, and Millennium projects are not transferred to the lenders or their 130

designees on or before March 31, 2003. Such a The Lake Road and La Paloma projects have default would trigger lender remedies, including been financed entirely with debt. PG&E NEG has the right to foreclose on the projects. Under the guaranteed the repayment of a portion of the waiver, PG&E NEG has re-affirmed its guarantee project subsidiary debt of approximately of GenHoldings' obligation to make equity $230 million for Lake Road and $375 million for contributions of approximately $355 million to La Paloma, which amounts represent the these projects. Neither PG&E NEG nor subsidiaries' equity contribution in the projects.

GenHoldings currently expects to have sufficient The lenders have demanded the immediate funds to make this payment. The requirement to payment of these equity contributions. Neither pay $355 million remains an obligation of PG&E the PG&E NEG subsidiaries nor PG&E NEG have NEG that would survive the transfer of the sufficient funds to make these payments. The projects. requirement to make the payments will remain an obligation of PG&E NEG that would survive In accordance with the provisions of SFAS the transfer of the projects.

No. 144 the long-lived assets of GenHoldings at December 31, 2002 were tested for impairment. In accordance with the provisions of SFAS As a result of the test, the assets were No. 144, the long-lived assets of the Lake Road determined to be impaired and were and La Paloma project subsidiaries at written-down to fair value. Based on the current December 31, 2002 were tested for impairment.

estimated fair value of these assets, GenHoldings As a result of the test, these assets were recorded a pre-tax loss from impairment of determined to be impaired and were

$1.147 billion in the fourth quarter of 2002. written-down to fair value. Based on the current estimated fair value of these assets, the Lake Impairment of Lake Road and La Paloma Road and La Paloma project subsidiaries Projects: On November 14, 2002, PG&E NEG recorded a pre-tax loss from impairment of defaulted under its equity commitment approximately $186 million and $266 million, guarantees for the Lake Road and the La Paloma respectively, in the fourth quarter of 2002.

credit facilities. As of December 4, 2002, PG&E NEG and certain of its subsidiaries entered into Impairment of Mantua Creek Project: The agreements with respect to each of the Lake Mantua Creek project is a nominal 897 megawatt Road and La Paloma generating projects (MW) combined cycle merchant power plant providing for (1) funding of construction costs located in the Township of West Deptford, New required to complete the La Paloma facility; and Jersey. Construction began in October 2001 and (2) additional working capital facilities to enable the project was 24 percent complete as of each subsidiary to timely pay for its fuel October 31, 2002. Due to liquidity concerns, requirements and to provide its own collateral to PG&E NEG could no longer provide equity support natural gas pipeline capacity reservations contributions to the project and efforts to sell the and independent transmission system operator project were unsuccessful. Beginning in the requirements, as well as for general working fourth quarter of 2002, contracts with vendors capital purposes. Lenders extending new credit were suspended or terminated to eliminate an under these agreements have received liens on increase in project costs. In December 2002, the the projects that are senior to the existing project provided notices of termination to the lenders' liens. These agreements provide, among Pennsylvania, New Jersey, Maryland Independent other things, that the failure to transfer right, title System Operator (PJM), and other significant and interest in, to and under the Lake Road and counterparties. With all significant contracts La Paloma projects to the respective lenders by terminated, PG&E NEG's subsidiary will abandon June 9, 2003 will constitute a default under the this project in early 2003. PG&E NEG's subsidiary agreements. The failure to transfer the facilities has written-off the capitalized development and would entitle the lenders to accelerate the new construction costs of $257 million at indebtedness and exercise other remedies. December 31, 2002. In addition, PG&E NEG has recorded an accrual of $22 million for charges 131

and associated termination costs at December 31, disputed that such amounts were due before 2002. January and July 2003 and has asserted that a breach under PG&E NEG's guarantee did not Impairment of Turbines and Other Related give rise to a breach of the turbine purchase Equipment7 To support PG&E NEG's electric agreement, neither PG&E NEG nor its subsidiary generating development program, PG&E NEG intends to contest the termination. The costs to subsidiaries had contractual commitments and terminate this contract were accrued for in the options to purchase a significant number of second quarter of 2002, as discussed above. On combustion turbines and related equipment. January 31, 2003, a termination payment of PG&E NEG subsidiaries' commitment to purchase $4.5 million was made with the remaining combustion turbines and related equipment amount of $9.5 million expected to be paid in exceeded the new planned development July 2003.

activities discussed herein. In the second quarter of 2002, these PG&E NEG subsidiaries Termination of Interest Rate Swaps on Lake recognized a pre-tax charge of $246 million. The Road, La Paloma and GenHoldings Projects:

charge consisted of the impairment of the As a result of the La Paloma and Lake Road previously capitalized costs associated with prior project subsidiaries' failure to make required payments made under the terms of the turbine equity payments under interest rate hedge and equipment contracts in the amount of contracts entered into by them, the

$188 million and an accrual of $58 million for counterparties to such interest rate hedge future termination payments required under the contracts have terminated the contracts.

turbine and related equipment contracts. In Settlement amounts due from the Lake Road and addition, at that time, the PG&E NEG subsidiaries La Paloma project subsidiaries in connection with retained capitalized prepayment costs associated such terminated contracts are, in the aggregate, with three development projects that were to be $61 million and $78 million, respectively. Further, further developed or sold. In the fourth quarter as a result of GenHoldings' failure to make of 2002, these PG&E NEG subsidiaries incurred required payments under interest rate hedge an additional pre-tax charge of $30 million for contracts entered into by GenHoldings, the the write-off of prior turbine prepayments counterparties to such interest rate hedge associated with the impairment of the remaining contracts terminated the contracts during development projects as discussed below. December 2002. Settlement amounts due by GenHoldings in connection with such terminated In November 2002, subsidiaries of PG&E NEG contracts are, in the aggregate, approximately reached agreement with General Electric $50 million. The La Paloma and Lake Road Company (GEC) to terminate its master turbine project subsidiaries and GenHoldings incurred a purchase agreement and with General Electric pre-tax charge to earnings in the fourth quarter International, Inc. (GEII) to terminate its master of 2002 for these amounts totaling $189 million.

long-term service agreement. GEC and GEII have agreed to reduce the termination fees from Impairment of Dispersed Generation-approximately $34 million to approximately PG&E NEG is seeking a buyer for PG&E

$22 million and to defer payment of the reduced Dispersed Generation LLC, Plains End LLC, fees to December 31, 2004. The costs to Dispersed Properties LLC and 100 percent of the terminate this contract were accrued for in the capital stock of Ramco Inc, (collectively, referred second quarter of 2002 as discussed above. to as Dispersed Gen Companies or Dispersed Generation). In accordance with the provisions Also in November 2002, Mitsubishi Power of SFAS No. 144, the long-lived assets of the Systems, Inc. (MPS) notified PG&E NEG's Dispersed Gen Companies were tested for subsidiary that it was terminating the turbine impairment. As a result of the test, these assets purchase agreement for failure to pay past due were determined to be impaired and were amounts and failure to collateralize PG&E NEG's written-down to fair value. Based on the current guarantee. While PG&E NEG's subsidiary has estimated fair value (based on the estimated 132

proceeds) of a sale, Dispersed Generation of approximately $57 million was recorded by recorded a pre-tax loss from impairment of these subsidiaries for their development assets

$88 million in the fourth quarter of 2002. This is (excluding associated equipment costs as in addition to a pre-tax loss from impairment of discussed above) in the fourth quarter of 2002.

$30 million that was recorded in the third quarter While these subsidiaries have impaired all of of 2002, which related to certain equipment their development projects, they have not (turbines, generators, transformers, etc.) that was abandoned the permits or rights to these purchased and/or refurbished and held for future projects. It is anticipated that these permits and expansion at current Dispersed Generation rights will be abandoned for all development facilities. projects in 2003.

Impairment of Goodwilk SFAS No. 142 Impairment of Soutbaven Power LLC Loan "Goodwill and Other Intangible Assets," requires Receivable: PG&E Energy Trading- Power, L.P.

that goodwill be reviewed at least annually for (PG&E ET) signed a tolling agreement with impairment. Due to significant adverse changes Southaven Power LLC (Southaven) dated June 1, within the national energy markets, PG&E NEG 2000, pursuant to which PG&E ET was required and it subsidiaries elected to test its goodwill for to provide credit support that meets certain possible impairment in the third quarter of 2002. requirements set forth in the agreement. PG&E Based upon the results of the fair value test, ET satisfied this obligation by providing an PG&E NEG and it subsidiaries recognized a investment-grade guarantee from PG&E NEG.

goodwill impairment loss of $95 million in the The original maximum amount of the guarantee third quarter of 2002. The fair value of the was $250 million. However, this amount was segment was estimated using the discounted reduced by approximately $74 million, the cash flows method. At December 31, 2002, there amount of a subordinated loan that PG&E ET was no goodwill remaining at PG&E NEG and it made to Southaven on August 31, 2002.

subsidiaries.

Southaven has advised PG&E ET that it believes Impairment of Development Costs: In the an event of default under the tolling agreement second quarter of 2002, PG&E NEG project has taken place with respect to the obligation for subsidiaries recognized an impairment loss a guarantee because PG&E NEG is no longer related to the capitalized costs associated with investment-grade as defined in the agreement certain development projects. These PG&E NEG and because PG&E ET has failed to provide, subsidiaries analyzed the potential future cash within 30 days from the downgrade, substitute flow from those projects that it no longer credit support that meets the requirements of the anticipated developing and recognized an agreement. Under the tolling agreement, impairment of the asset value it was carrying for Southaven has the right to terminate the those projects. The aggregate pre-tax impairment agreement and seek a termination payment. In charge recorded by these PG&E NEG subsidiaries addition, PG&E ET has provided Southaven with for its development assets (excluding associated a notice of default with respect to Southaven's equipment) was $19 million recorded in the performance under the tolling agreement. If this second quarter of 2002. At that time, these PG&E default is not cured, PG&E ET has the right to NEG subsidiaries continued to develop or terminate the agreement and seek recovery of a planned to sell three additional projects. These termination payment. On February 4, 2003, subsidiaries have ceased developing these PG&E ET provided a notice of termination.

projects and sought to sell the development Southaven has objected to the notice and has assets. To date, these subsidiaries have been filed suit in connection with this matter. PG&E unsuccessful in selling these projects and have ET has recorded an impairment of the loan tested the capitalized costs associated with the receivable due to the uncertainty associated with projects for impairment at December 31, 2002. the recoverability of the loan, which was Based upon the results of these tests, an subordinate to the senior debt of the project and additional aggregate pre-tax impairment charge 133

reliant upon operations of the plant under the No default has occurred under the related lease terms of the tolling agreement. and Attala Generating timely made the

$22.2 million lease payment due on January 2, Impairment of PrepaidRents on Attala 2003. However, the lease provides that failure to Lease: On May 7, 2002, Attala Generating replace the tolling agreement with a satisfactory Company LLC (Attala Generating), an indirect replacement tolling agreement within 180 days wholly owned subsidiary of PG&E NEG, after the first default under the tolling agreement, completed a $340 million sale and leaseback which occurred on November 27, 2002, will transaction whereby it sold and leased back its constitute an event of default under the lease.

approximately 526 MW generation facility located After the termination payment has been in Mississippi to a third-party special purpose determined in accordance with the tolling entity. agreement and if Attala Energy or PG&E NEG both fail, or have failed, to provide security as PG&E NEG has provided a $300 million required by the tolling agreement, the time guarantee to support the payment obligations of period would not extend beyond the 60"' day another indirect wholly owned subsidiary, Attala after such failure to provide security. Upon the Energy Company LLC (Attala Energy) under a occurrence of an event of default under the tolling agreement entered into with Attala lease, the lessor would be entitled to exercise Generating. The payments under the 25-year various remedies, including termination of the term tolling agreement provide Attala lease and foreclosure of the assets securing the Generating, as lessee, with sufficient cash flows lease. At December 31, 2002, Attala Generating during the term of the tolling agreement to pay wrote-off prepaid rental payments of $43 million rent under a 37-year lease and certain other due to the uncertainty of future cash flows operating costs. Due to current energy market associated with the lease.

conditions, Attala Energy is unable to make the payments under the tolling agreement and failed Impairment of Kentucky Hydro Pr"ect:

to make the required payment due on The Kentucky Hydro Generating Project consists November 22, 2002 to Attala Generating. Failure of two run-of-river hydroelectric power plants to cure this payment default constituted an event located in Kentucky on the Ohio River. The of default under the tolling agreement as of project negotiated a turnkey, fixed price contract November 27, 2002. Further, PG&E NEG's failure with VA Tech MCE Corporation (VA Tech) and to pay maturing principal under its Corporate issued a limited notice to proceed in Revolver on November 14, 2002, became an August 2001. Beginning in the fourth quarter of event of default under the tolling agreement 2002, all work on the project was suspended upon Attala Energy's failure to replace the PG&E except for minimal expenditures to maintain the NEG guarantee by December 16, 2002. On Federal Energy Regulatory Commission licenses.

December 31, 2002, the tolling agreement The termination cost due to VA Tech of terminated following notice of termination given approximately $14 million was fully paid. VA by Attala Generating. The parties are currently Tech terminated the contract effective determining the termination payment, if any, that December 6, 2002. As part of the settlement of Attala Energy would owe Attala Generating. PG&E NEG subsidiary's partnership arrangement, Despite the termination of the tolling this subsidiary assigned its partnership interest to agreements, Attala Energy remains obligated to the original developer, W.V. Hydro, on provide an acceptable guarantee or collateral to February 7, 2003. PG&E NEG has written-off the secure its obligations under the tolling capitalized development and construction costs agreement, including the payment of any and provided for all termination costs by termination payment that may be determined to recording a pre-tax charge of $18 million at be due. December 31, 2002.

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NOTE 8: ACQUISMONS AND DISPOSAIS On November 5, 2002, PG&E NEG announced its plan to shut down its Spencer Station generating Sale of Interest in Hermiston - On plant located in Denton, Texas. However, PG&E November 4, 2002, affiliates of PG&E ET entered NEG did not shut down Spencer Station and into an agreement to sell 49.9 percent of its instead sold Spencer Station to the City of ownership interest in Hermiston Generating Garland on February 13, 2003. In addition, PG&E Company, L.P. (HGC) to Sumitomo Corporation ET has sold its obligation to supply the full and Sumitomo Corporation of America. The service power requirements of the City of buyer was granted an option to purchase, during Denton. Based on the current fair value (based the three-month period beginning 13 months on the proceeds) of a sale of Spencer Station, immediately following the closing date, an PG&E NEG will record an immaterial gain in the additional 0.1 percent interest (at the fair market first quarter of 2003.

value at the date of exercise). HGC owns an undivided 50.01 percent interest in a 474 MW Purcbase of Attala - On September 28, 2000, gas-fired generating plant in Hermiston, Oregon. PG&E NEG purchased for $311 million Attala The other 49.99 percent is owned by PacifiCorp, Generating, which owns a gas-fired power plant which also purchases the output of the plant that was under construction. Under the purchase under a long-term contract. The sale was agreement, PG&E NEG prepaid the estimated completed on December 20, 2002, following the remaining construction costs, which were being receipt of necessary regulatory approvals. PG&E managed by the seller. The project, which was NEG received $46 million in proceeds for the approximately 82 percent complete as of sale of HGC resulting in a pre-tax $11 million December 31, 2000, began commercial service in gain, after the sale of a net investment balance June 2001. In connection with the acquisition, of $25 million and reversal of Other PG&E NEG also assumed industrial revenue Comprehensive Income of $10 million. Gain bonds issued by the Mississippi Business Finance from the sale of HGC is included in other Corporation in the amount of $159 million, operating expenses. Prior to this sale of under an agreement that the seller would pay off partnership interest, PG&E NEG owned 100 of the bonds. Accordingly, a $159 million receivable this partnership and was fully consolidating HGC was recorded. At December 31, 2001, the seller into its results. had paid off the bonds. See Note 7 for a current status of this facility.

Sale of DevelopinentAssets - On July 10, 2001, PG&E NEG completed the sale of certain Sale of PG&E G7T- On January 27, 2000, development assets, resulting in a pre-tax gain of PG&E NEG signed a definitive agreement with El

$23 million. Paso Field Services Company (El Paso) providing for the sale of the stock of PG&E GTT to El Purcbaseand Closing of Spencer Paso, a subsidiary of El Paso Energy Corporation.

Station - On June 29, 2001, PG&E ET On December 22, 2000, after receipt of contracted to supply the full service power governmental approvals, PG&E NEG completed requirements of the city of Denton, Texas, for a the stock sale. The total consideration received period of five years beginning July 1, 2001. was $456 million, less $150 million used to retire PG&E Er's supply obligation to the city was net the PG&E GlTs short-term debt, and the of approximately 97 megawatts of generation assumption by El Paso of PG&E GTIrs long-term entitlements retained by the city, plus 40 debt having a book value of $564 million. PG&E megawatts of purchased power that the city had Corporation's Consolidated Statements of assigned to PG&E ET for the summer of 2001. Operations included $33 million of net income Another affiliate of PG&E NEG acquired a 178 related to the year ended December 31, 2000.

megawatt generating station and two small hydroelectric facilities from the city. The total consideration was approximately $12 million for this transaction.

135

NOTE 9: COMMON STOCK LLC, a subsidiary of the Utility, hold all of the Utility's outstanding common stock.

PG&E Corporation The Utility did not repurchase any shares of its PG&E Corporation has authorized 800 million common stock during the year ended shares of no-par common stock of which December 31, 2002, and 2001. In April 2000, 405 million shares were issued and outstanding PG&E Holdings LLC repurchased 11.9 million at December 31, 2002, and 388 million at shares of the Utility's common stock at a cost of December 31, 2001. $275 million. At December 31, 2002, and 2001, the Utility held repurchased common stock PG&E Corporation repurchased $0.5 million of totaled 19.5 million shares, at a cost of its common stock during the year ended $475 million. The repurchased common stock is December 31, 2001. The repurchases were made included as a reduction of stockholders' equity to satisfy obligations under the Dividend on the Utility's Consolidated Balance Sheets.

Reinvestment Plan. PG&E Corporation repurchased approximately $5,000 of its common In October 2000, the Utility declared a stock during the year ended December 31, 2002. $110 million common stock dividend to PG&E PG&E Corporation is precluded by the terms of Corporation and PG&E Holding LLC. In the Credit Agreement from repurchasing any January 2001, the Utility suspended payment of more of its common stock until the Loans are the declared dividend. The suspension was made repaid. so that the Utility could maintain its CPUC-authorized capital structure, which is the On March 2, 2001, PG&E Corporation paid its level of common and preferred equity the Utility suspended fourth quarter 2000 stock dividend of may maintain in relation to its debt.

$0.30 per common share, declared by the Board of Directors on October 18, 2000, to The Utility did not declare or pay common and shareholders of record as of December 15, 2000. preferred stock dividends in 2001 and 2002.

Preferred stock dividends have a cumulative On January 2, 2003, the Board of Directors feature in which any preferred stock dividends granted 1.6 million shares of PG&E Corporation not paid in any year must be made up in a later restricted stock under the PG&E Corporation year before any dividends can be distributed to Long-Term Incentive Program. Over the period common stockholders. As a result, the Utility of four years, restrictions will lapse as to may not pay any dividends on its common stock 20 percent of the total number of shares of until the cumulative preferred stock dividends restricted stock each year. Restrictions will lapse and mandatory preferred sinking fund as to an additional 5 percent of the total number requirements are paid.

of shares of restricted stock each year, if PG&E Corporation is in the top quartile of its NOTE 10: PREFERRED STOCK comparator group. This is measured by relative annual total shareholder return for the year Shareholder Rights Plan of PG&E ending immediately before each annual lapse Corporation date. (See Note 14.)

On December 20, 2000, the Board of Directors of Utility PG&E Corporation declared a distribution of preferred stock purchase rights (the Rights) at a The Utility is authorized to issue 800 million rate of one right for each outstanding share of shares of its $5 par value common stock. Of the PG&E Corporation common stock. The Rights total shares authorized, 321 million shares were apply to outstanding shares of PG&E Corporation issued and outstanding as of December 31, 2002, common stock held as of the close of business and 2001. PG&E Corporation and PG&E Holding on January 2, 2001, and for each share of common stock issued by PG&E Corporation 136

thereafter and before the "distribution date," as In the event of liquidation, the holder of a Unit described below. Each Right entitles the will receive a preferred liquidation payment.

registered holder, in certain circumstances, to purchase from PG&E Corporation one The Rights also have certain anti-takeover effects one-hundredth of a share (a Unit) of PG&E and will cause substantial dilution to a person or Corporation's Series A Preferred Stock, par value group that attempts to acquire PG&E Corporation

$100 per share, at an initially fixed purchase on terms not approved by PG&E Corporation's price of $95 per Unit, subject to adjustment. Board of Directors, unless the offer is Effective December 22, 2000, the PG&E conditioned on a substantial number of Rights Corporation Dividend Reinvestment Plan was being acquired. The Rights should not interfere modified to note these changes. with any approved merger or other business combination, as the Board of Directors, at its The Rights are not exercisable until the option. may redeem the Rights. Thus, the Rights distribution date and will expire December 22, are intended to encourage persons who may' 2010, unless redeemed earlier by the PG&E seek to acquire control of PG&E Corporation to Corporation Board of Directors. The distribution initiate such an acquisition through negotiations date will occur upon the earlier of (1) 10 days with PG&E Corporation's Board of Directors.

following a public announcement that a person However, the effect of the Rights may be to or group (other than PG&E Corporation, any of discourage a third party from making a partial its subsidiaries, or its employee benefit plans) tender offer or otherwise attempting to obtain a has acquired or obtained the right to acquire substantial equity position in the equity securities beneficial ownership of 15 percent or more of of, or seeking to obtain control of, PG&E the then-outstanding shares of PG&E Corporation Corporation. To the extent any potential common stock, and (2) 10 business days (or acquirers are deterred by the Rights, the Rights later, as determined by the Board of Directors) may have the effect of preserving incumbent following the commencement of a tender offer management in office.

or exchange offer that would result in a person or group owning 15 percent or more of the Preferred Stock of Utility then-outstanding shares of PG&E Corporation common stock. After the distribution date, The Utility has authorized 75 million shares of certain triggering events will enable the holder of $25 par value preferred stock, which may be each Right (other than a potential acquirer) to issued as redeemable or non-redeemable purchase Units of Series A Preferred Stock preferred stock.

having twice the market value of the initially fixed exercise price, i.e., at a 50 percent At December 31, 2002, and 2001, the Utility had discount. Until a Right is exercised, the holder issued and outstanding 5,784,825 shares of shall have no Rights as a shareholder of PG&E non-redeemable preferred stock. Holders of the Corporation, including without limitation the Utility's non-redeemable preferred stock right to vote or to receive dividends. 5.0 percent, 5.5 percent, and 6.0 percent series have rights to annual dividends per share A total of 5 million shares of preferred stock will ranging from $1.25 to $1.50.

be reserved for issuance upon exercise of the Rights. The Units of preferred stock that may be At December 31, 2002, and 2001, the Utility had acquired upon exercise of the Rights will be issued and outstanding 5,973,456 shares of non-redeemable and subordinate to any other redeemable preferred stock. The Utility's shares of preferred stock that may be issued by redeemable preferred stock is subject to PG&E Corporation. Each Unit of preferred stock redemption at the Utility's option, in whole or in will have a minimum preferential quarterly part, if the Utility pays the specified redemption dividend rate of $0.01 per Unit but will, in any price plus accumulated and unpaid dividends event, be entitled to a dividend equal to the per through the redemption date. At December 31, share dividend declared on the common stock. 2002, annual dividends ranged from $1.09 to 137

$1.76 and redemption prices ranged from $25.75 dividend and liquidation rights. Accumulated and to $27.25. unpaid preferred stock dividends amounted to

$50 million as of December 31, 2002, and At December 31, 2002, the Utility's redeemable $25 million as of December 31, 2001. Upon preferred stock with mandatory redemption liquidation or dissolution of the Utility, holders provisions consisted of 3 million shares of the of preferred stock would be entitled to the par 6.57 percent series and 2.5 million shares of the value of such shares plus all accumulated and 6.30 percent series. These series are redeemable unpaid dividends, as specified for the class and at par value plus accumulated and unpaid series. Until cumulative dividends on its dividends through the redemption date. The preferred stock and mandatory preferred sinking 6.57 percent series may be redeemed at the fund payments are paid, the Utility may not pay Utility's option on or after July 31, 2002. The any dividends on its common stock, nor may the 6.30 percent series may be redeemed at the Utility repurchase any of its common stock. A Utility's option on or afterJanuary 31, 2004. sinking fund sets aside funds for the future These series of preferred stock are subject to periodic retirement of the outstanding stocks.

mandatory redemption provisions entitling them to sinking funds providing for the retirement of Preferred Stock of PG&E NEG the stock outstanding.

Preferred stock of PG&E NEG consists of The redemption requirements for the Utility's $58 million of preferred stock issued by a redeemable preferred stock with mandatory subsidiary of PG&E NEG. The preferred stock, redemption provisions are for the 6.57 percent with $100 par value, has a stated non-cumulative series $4 million per year from 2002 through quarterly dividend of $3.35 per share, per 2006, and $55 million in 2007, and for the quarter, and is redeemable when there is an 6.30 percent series, $3 million per year from excess of available cash. There were 549,594 2004 through 2008, and $47 million in 2009. shares of preferred stock outstanding at December 31, 2002, and 2001.

Due to the California energy crisis, the Utility's Board of Directors did not declare the following NOTE 11: PRICE RISK MANAGEMENT regular preferred stock dividends normally payable 15 days after the three-month periods As previously discussed, PG&E NEG is in the ended: process of reducing and unwinding its trading positions. Additionally, asset hedge positions

. January 31, 2001; associated with the merchant plants will either

• April 30, 2001; remain with the assets or be terminated. PG&E NEG has significantly reduced their energy

• July 31, 2001; trading operations in an ongoing effort to raise

• October 31, 2001; cash and reduce debt. PG&E NEG's objective is to limit its asset trading and risk management

. January 31, 2002; activities to only what is necessary for energy

• April 30, 2002; management services to facilitate the transition of PG&E NEG's merchant generation facilities

. July 31, 2002; through their sale, transfer or abandonment

. October 31, 2002; and process. PG&E NEG will then further reduce and transition to only retain limited capabilities to

• January 31, 2003.

ensure fuel procurement and power logistics for Dividends on all Utility preferred stock are PG&E NEG's retained independent power plant operations.

cumulative. All shares of preferred stock have voting rights and an equal preference in 138

Non-Trading Activities PG&E Corporation's net derivative losses included in OCT at December 31, 2002, were $90 At December 31, 2002, PG&E Corporation had million, of which approximately $70 million is cash flow hedges of varying durations associated expected to be reclassified into earnings within with commodity price risk, interest rate risk, and the next 12 months based on the contractual foreign currency risk, the longest of which terms of the contracts or the termination of the extend through December 2011, March 2014, and hedge position. The actual amounts reclassified December 2004, respectively. from OCT to earnings will differ as a result of market price changes. The Utility did not have The amount of commodity hedges included in any cash flow hedges at December 31, 2002, or Accumulated Other Comprehensive Income or December 31, 2001. The Utility's ineffective Loss (OCI), net of tax, at December 31, 2002, portion of changes in amounts of cash flow was a loss of $27 million. The amount of interest hedges was immaterial for the year ended rate hedges included in OCI, net of tax, at December 31, 2001.

December 31, 2002, was a loss of $61 million.

The amount of foreign currency hedges included in OCT, net of tax, at December 31, 2002, was a loss of $2 million.

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

(in mions) Year Ended December 31, 2002 2001 PG&E PG&E Corporation Utility Corporation Utility Derivative gains included in accumulated other comprehensive income at beginning of period .................................. $ 36 - $ -

Cumulative effect of adoption of SFAS No. 133 ................... (243) 90 Net gain (loss) from current period hedging transactions and price changes (139) - 237 (5)

Net reclassification to earnings ............................. 13 - 42 (85)

Derivative gains (losses) included in accumulated other comprehensive income at end of period ............................... (90) - 36 Foreign currency translation adjustment ....................... (3) - (5) (2)

Other ............................................ (1)

Accumulated other comprehensive income (loss) at end of period ....... $ (93) - $ 30 $ (2)

For most non-trading activities, earnings are However, in a few instances, non-trading recognized on an accrual basis as revenues are activities affect PG&E NEG's earnings on a earned and as expenses are incurred. Thus, most mark-to-market basis. PG&E NEG recognizes the non-trading activities do not affect earnings on a ineffective portion of the fair value of cash flow mark-to-market basis. For example, the effective hedges in earnings. PG&E NEG also has certain portion of contracts accounted for as cash flow derivative contracts, which, while they are meant hedges have no mark-to-market effect on for non-trading purposes, do not qualify for cash earnings; these contracts are presented on a flow hedge accounting or for the normal mark-to-market basis on the balance sheet in purchases and sales exception to SFAS No. 133.

PRM assets and liabilities and OCT. Other These derivatives are reported in earnings on a non-trading contracts are exempt from the SFAS mark-to-market basis. These contracts primarily No. 133 fair value requirements under the consist of those derivative commodity contracts normal purchases and sales exception and thus for which normal purchases and sales treatment have no mark-to-market effect on earnings. was disallowed upon PG&E NEG's 139

implementation of DIG C15 and C16 effective Realized gains and losses from trading activities April 1, 2002 (see Note 1). also are presented on a net basis in operating revenues, beginning in the third quarter of 2002, The effects on pre-tax earnings of non-trading as more fully described in Note 1.

activities that are reflected in income on a mark-to-market basis are as follows: Gains and losses on trading contracts affect PG&E Corporation's gross margin in the Year Ended accompanying PG&E Corporation unaudited December (in milions) 31, Consolidated Statements of Income on an 2002 2001 unrealized, mark-to-market basis as the fair value of the forward positions on these contracts Ineffective portion of cash flow hedges . . . S (2) $ -

Earnings from discontinued cash flow fluctuate. Settlement or delivery on a contract hedges ...................... (203) - generally does not result in incremental net Non-trading derivatives marked-to-market income recognition, because the profit or loss on through earnings .............. (78) 19 a contract is recognized in income on an Total ... ..................... $(283) $ 19 unrealized, mark-to-market basis during the periods before settlement occurs.

The $203 million pre-tax loss from discontinuance of cash flow hedges is primarily Gains and losses on trading contracts affect PG&E Corporation's cash flow when these due to the interest rate hedges. Accounting hedge treatment was discontinued when certain contracts are settled. Net realized gains reported in the table below primarily reflect the net effect PG&E NEG subsidiaries failed to make payments of contracts that have been settled in cash. Net under their debt agreements and, therefore, the hedged transactions were no longer considered realized gains also include certain non-cash probable of occurrence. The $189 million loss in items, including amortization of option premiums that were paid or received in cash in earlier OCI relating to the interest rate hedges was periods, but are considered realized when the reclassified to earnings, in accordance with the provisions of SFAS No. 133. (See further related options are exercised or expire.

discussions in Note 3, GenHoldings Construction PG&E Corporation's net gains (losses) on trading Facility and Lake Road and La Paloma Construction Facilities.) The remainder of the activities are as follows:

$203 million pre-tax loss relates to financial Year Ended commodity hedges that were discontinued after (in millions) December 31, the hedged transactions were no longer 2002 2001 2000 considered probable of occurrence. Trading activities:

Unrealized gains (losses), net ... . $ (74) $(120) $ 31 Trading Activities Realized gains, net ..... ..... 121 296 174 Total ........... 47 $ 176

$........ $205 Unrealized gains and losses from trading activities, including the reversal of unrealized gains and losses previously recognized on See Note 1 for a discussion of the rescission of contracts that go to settlement or delivery, are E1TF 98-10, which impacted the accounting for presented on a net basis in operating revenues. trading activities.

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Price Risk Management Assets and Liabilities calculated on a mark-to-market basis for contracts that will be settled in future periods.

PRM assets and liabilities on the accompanying PRM assets and liabilities at December 31, 2002, PG&E Corporation Consolidated Balance Sheets include amounts for trading and non-trading reflect the aggregation of the fair values of activities, as described below:

outstanding contracts. These fair values are Net Assets (in millions) PM Assets P1W Liabiitles (liabilities)

Current Noncurrent Current Noncurrent December 31, 2002 Trading activities .................... $351 $232 $(349) $(236) $ (2)

Non-trading activities:

Cash flow hedges - offset to OCI .......... 130 101 (155) (69) 7 Derivatives marked to market through earnings .......................... 17 65 (2) 80 Total consolidated PRM Assets and lIabilities ........................ $498 $398 $(506) $(305) $ 85 Non-trading activities include certain long-term obligations (these obligations are reflected as contracts that are not included in PG&E Accounts Receivable-Customers, net; notes Corporation's trading portfolio but that, due to receivable included in Other Noncurrent certain pricing provisions and volumetric Assets-Other; PRM assets; and Assets held for variability, are unable to receive hedge sale on the balance sheet). PG&E Corporation accounting treatment or the normal purchases and the Utility conduct business primarily with and sales exception, as outlined by customers or vendors, referred to as interpretations of SFAS No. 133. PG&E counterparties, in the energy industry. These Corporation has certain other non-trading counterparties include other investor-owned derivative commodity contracts for the physical utilities, municipal utilities, energy trading delivery of purchases and sales quantities companies, financial institutions, and oil and gas transacted in the normal course of business. production companies located in the United These other non-trading activities include States and Canada. This concentration of contracts that are exempt from SFAS No. 133 fair counterparties may impact PG&E Corporation's value requirements under the normal purchases and the Utility's overall exposure to credit risk and sales exemption, as described previously. because their counterparties may be similarly Although the fair value of these other affected by economic or regulatory changes or non-trading contracts is not required to be other changes in conditions.

presented on the balance sheet, revenues and expenses generally are recognized in income PG&E Corporation and the Utility manage their using the same timing and basis as are used for credit risk in accordance with their respective the non-trading activities accounted for as cash Risk Management Policies. The policies establish flow hedges. Hence, revenues are recognized as processes for assigning credit limits to earned and expenses are recognized as incurred. counterparties before entering into agreements with significant exposure to PG&E Corporation CreditRisk and the Utility. These processes include an evaluation of a potential counterparty's financial Credit risk is the risk of loss that PG&E condition, net worth, credit rating, and other Corporation and the Utility would incur if credit criteria as deemed appropriate, and are counterparties failed to perform their contractual performed at least annually.

141

Credit exposure is calculated daily, and in the of credit, as this collateral is not affected by a event that exposure exceeds the established credit rating downgrade.

limits, PG&E Corporation and the Utility take immediate action to reduce the exposure, or For the year ended December 31, 2002, PG&E obtain additional collateral, or both. Further, Corporation and the Utility have recognized no PG&E Corporation and the Utility rely heavily on losses due to the contract defaults or master agreements that require the counterparty bankruptcies of counterparties. However, in to post security, referred to as credit collateral, in 2001, PG&E Corporation terminated its contracts the form of cash, letters of credit, corporate with a bankrupt company, which resulted in a guarantees of acceptable credit quality, or pre-tax charge to earnings of $60 million related eligible securities if current net receivables and to trading and non-trading activities, after replacement cost exposure exceed contractually application of collateral held and accounts specified limits. payable.

PG&E Corporation and the Utility calculate gross At December 31, 2002, and at December 31, credit exposure for each counterparty as the 2001, PG&E Corporation had no single current mark-to-market value of the contract counterparty that represented greater than 10 (that is, the amount that would be lost if the percent of PG&E Corporation's net credit counterparty defaulted today) plus or minus any exposure. At December 31, 2002, the Utility had outstanding net receivables or payables, prior to one investment-grade counterparry that the application of the counterparty's credit represented 21 percent of the Utility's net credit collateral. exposure, and one below investment-grade counterparty that represented 11 percent of the In 2002, PG&E Corporation's and the Utility's Utility's net credit exposure. At December 31, credit risk increased due in part to downgrades 2001, the Utility had no single counterparty that of some counterparties credit ratings to levels represented greater than 10 percent of the below investment grade. The downgrades Utility's net credit exposure.

increase PG&E Corporation's or the Utility's credit risk because any collateral provided by The schedule below summarizes PG&E these counterparties in the form of corporate Corporation's and the Utility's credit risk guarantees or eligible securities may be of lesser exposure to counterparties that are in a net asset or no value. Therefore, in the event these position, with the exception of exchange-traded counterparties failed to perform under their futures (the exchange provides for contract contracts, PG&E Corporation and the Utility may settlement on a daily basis), as well as PG&E face a greater potential maximum loss. In Corporation's and the Utility's credit risk contrast, PG&E Corporation and the Utility do exposure to counterparties with a greater than not face any additional risk if counterparties' 10 percent net credit exposure, at December 31, credit collateral is in the form of cash or letters 2002, and December 31, 2001:.

Gross Credit Exposure Befbre Number of Net Exposure of Credit Credit Net Credit Counterpartles Counterpartles (In millions) Collateral (1) Collateral (2) Exposure (2) >10% >10%0 At December 31, 2002 PG&E Corporation S1,165 $195 $970 Utility (3) 288 113 175 2 55 At December 31, 2001 PG&E Corporation $1,203 $207 $996 Utility 3X 271 127 144

") Gross credit exposure equals mark-to-market value (adjusted for applicable credit valuation adjustments), notes receivable, and net (payables) receivables where netting is allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value, liquidity, or model.

t2 Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit).

(3} The Utility's gross credit exposure indudes wholesale activity only. Retail activity and payables incurred prior to the Utility's bankruptcy filing are not included. Retail activity at the Utility consists of the accounts receivable from the sale of gas and electricity to millions of residential and small commercial customers.

142

At December 31, 2002, approximately potential loss from nonpayment by these

$205 million, or 21 percent of PG&E customers based on historical experience. The Corporation's net credit exposure, was to entities Utility has a net regional concentration of credit that have credit ratings below investment grade. exposure totaling $175 million to counterparties At December 31, 2002, approximately that conduct business primarily throughout North

$64 million, or 37 percent of the Utility's net America.

credit exposure was to entities that had credit ratings below investment grade. At December 31, NOTE 12: ENVESTMENTS IN AFFIATES 2001, approximately $244 million, or 25 percent AND REILATED PARTY of PG&E Corporation's net credit exposure, was TRANSACTIONS to entities that had credit ratings below investment grade. At December 31, 2001, Investment in Unconsoldated Affiliates approximately $32 million, or 22 percent of the Utility's net credit exposure, was to entities that Utility had credit ratings below investment grade.

Investment grade is determined using publicly The Utility has investments in unconsolidated available information, i.e. rated at least Baa3 by affiliates, which are mainly engaged in the Moody's and BBB- by S&P. If the counterparty purchase of residential real estate property. The provides a guarantee by a higher rated entity equity method of accounting is applied to the (e.g., its parent), the credit rating determination Utility's investment in these entities. Under the is based on the rating of its guarantor. equity method, the Utility's share of equity income or losses of these entities is reflected as At December 31, 2002, approximately equity in.earnings of affiliates. As of

$65 million, or 7 percent of PG&E Corporation's December 31, 2002, the Utility's recorded net credit exposure was with counterparties at investment in these entities totaled $15 million.

PG&E NEG that were not rated. At December 31, As a limited partner, the Utility's exposure to 2001, none of PG&E Corporation's net credit potential loss is limited to its investment in each exposure was with counterparties at PG&E NEG partnership.

that were not rated. Most counterparties with no credit rating are governmental authorities which PG&E NEG are not rated, but which PG&E Corporation has assessed as equivalent to investment grade. PG&E NEG has non-controlling investments in Other counterparties with no credit rating are various power generation and other energy subject to an internal assessment of their credit projects. The equity method of accounting is quality and a credit rating designation. applied to such investments in affiliated entities, which include corporations, joint ventures and PG&E Corporation's regional concentrations of partnerships, due to the ownership structure credit exposure are to counterparties that preventing PG&E NEG from exercising control.

conduct business primarily in the western United Under this method, PG&E NEG's share of equity States and also to counterparties that conduct income or losses of these entities is reflected as business primarily throughout North America. revenue on the accompanying financial Additionally, the Utility's concentration of credit statements.

risk reflects its receivables from residential and small commercial customers in northern PG&E NEG's share of ownership in these California. However, the risk of material loss due affiliates ranges from 5 percent to 64 percent, to nonperformance from these customers is not and its net investment amounted to $403 million considered likely. Reserves for uncollectible as of December 31, 2002, and $414 million as of accounts receivable are provided for the December 31, 2001.

143

Net gains from the sale of interests in expense. The yearly purchase premium unconsolidated affiliates were $21 million during amortization expenses were $7 million in 2002, 2000, excluding PG&E NEG's pipeline interests $7 million in 2001, and $7 million in 2000.

that were sold as part of the GfT disposition.

Amounts are included in other operating Related Party Agreements and Transactions expenses. There were no sales of unconsolidated affiliates in 2002 or 2001. In accordance with various agreements, the Utility and other subsidiaries provide and receive The following table sets forth summarized various services to and from their parent, PG&E financial information of PG&E NEG's investments Corporation. The Utility and PG&E Corporation in affiliates accounted for under the equity exchange administrative and professional support method for the years ended December 31, 2002, services in support of operations. These services 2001, and 2000: are priced either at the fully loaded (i.e., direct costs and allocations of overhead costs) or at the Year Ended higher of fully loaded costs or fair market value, (in millions) December 31, 2002 2001 2000 depending on the nature of the services Statement of Operations Data provided. PG&E Corporation also allocates Revenues .............. $1,141 $1,150 $1,252 Income From Operations ..... 418 482 491 certain other corporate administrative and Earnings Before Taxes ...... 341 295 197 general costs to the Utility and other subsidiaries Equity in earnings from affiliates . 48 79 65 using a variety of factors when allocating these costs, which are based upon the number of As of employees, operating expenses, excluding fuel December 31, 2002 2001 purchases, total assets, and other cost causal Balance Sheet Data methods. Additionally, the Utility purchases gas Current assets .................. $ 309 $ 306 Noncurrent assets ............... 3,846 3,567 commodity and transmission services from, and Total Assets sells reservation and other ancillary services to

................ $4,155 $3.873 PG&E NEG. These services are priced at either Current liabilities ................ $ 788 $ 274 tariff rates or fair market value depending on the Noncurrent liabilities ............ 2,613 3,074 nature of the services provided. Intercompany Equity ...................... 754 525 transactions are eliminated in consolidation and Total Liabilities and Equity ........ $4,155 $3,873 no profit results from these transactions. The Utility's significant related party transactions were The reconciliation of the PG&E NEG's share of as follows:

equity to investment balance is as follows:

Year ended (in millions) December 31, As of -

(in millions) December 31, 2002 2001 2000 2002 2001 Utility proceeds froms Administrative services provided to PG&E NEG's share of equity ......... $ 95 $112 Purchase premium over book value ....

PG&E Corporation ......... $ 7 $ 6 $ 12 126 131 Gas reservation services provided Lease receivables and other investments . . 182 171 to PG&E ET ............. 9 11 12 Investments in unconsolidated affiliates . . $403 $414 Contribution in aid of construction received from PG&E NEG ..... 2 5 3 Other ................... - 1 2 The purchase premium over book value is being Trade Deposit due from PG&E amortized over periods ranging from 16 to GTNW ................ - 11 -

35 years and is recorded through amortization 144

Year ended being recognized proportionately over the (in mflons) December 31, license term of each facility.

2002 2001 2000 Utility payments for.

Administrative services received At December 31, 2002, the total nuclear from PG&E Corporation ...... $106 $127 $ 83 decommissioning obligation accrued was Interest on Debt to PG&E $1.3 billion and is included in accumulated Corporation .............. 8 3 3 depreciation and decommissioning on PG&E Administrative services received from PG&E NEG........... 2 - - Corporation's and the Utility's Consolidated Gas commodity and transmission Balance Sheets.

services received from PG&E ET. 49 120 136 Interest on Debt to PG&E ET .... 2 - - On January 1, 2003, the Utility adopted SFAS Transmission services received from No. 143. Under SEAS No. 143, the Utility will PG&E GTN .............. 47 40 46 adjust its nuclear decommissioning obligation to Trade Deposit due to ET .......

7 reflect the fair value of decommissioning its niucleanr nnuo!r Facilities See Note 1 uinder NOTE 13: NUCLEAR DECOMMISSIONING Adoption of New Accounting Policies -

Accounting for Asset Retirement Obligations.

Decommissioning of the Utility's nuclear power facilities is scheduled to begin, for ratemaking On March 15, 2002, the Utility filed its 2002 purposes, in 2015 and scheduled for completion Nuclear Decommissioning Cost Triennial in 2041. Nuclear decommissioning means (1) the Proceeding (NDCTP), seeking to increase its safe removal of nuclear facilities from service, nuclear decommissioning revenue requirements and (2) the reduction of residual radioactivity to for the years 2003 through 2005 based on the a level that permits termination of the Nuclear February 2002 cost study. The Utility's NDCTP Regulatory Commission license and release of seeks recovery of $24 million in revenue the property for unrestricted use.

requirements relating to the Diablo Canyon Nuclear Decommissioning Trusts and The estimated total obligation for nuclear

$17.5 million in revenue requirements relating to decommissioning costs at Diablo Canyon Power the Humboldt Bay Power Plant Plant and Humboldt Bay Power Plant is Decommissioning Trusts. The NDCTP also seeks

$1.9 billion in 2002 dollars (or $8.4 billion in recovery of $7.3 million in CPUC-jurisdictional future dollars). This estimate is (1) based on a revenue requirements for Humboldt Bay Unit 3 February 2002 decommissioning cost study, and operating and maintenance costs. These costs (2) includes labor, materials, waste disposal and include the radiation protection, surveillance other costs. The Utility plans to fund these costs activities, security forces, and maintenance of from independent decommissioning trusts, which security systems. The Utility proposes continuing receive annual contributions as discussed further to collect the revenue requirement through a below. The Utility estimates after-tax annual non-bypassable charge in electric rates, and to earnings, including realized gains and losses, on record the revenue requirement and the the tax-qualified decommissioning funds of associated revenues in the Nuclear 6.34 percent and non-tax-qualified Decommissioning adjustment mechanism decommissioning funds of 5.39 percent. The balancing account. The balancing account would decommissioning cost estimates are based on the require the Utility to return to ratepayers any plant location and cost characteristics for the amounts collected as part of the Utility's nuclear Utility's nuclear plants. Actual decommissioning decommissioning revenue requirement that were costs are expected to vary from this estimate not contributed to the independent trusts.

because of changes in assumed dates of decommissioning, regulatory requirements, Until post-rate freeze ratemaking is implemented, technology, costs of labor, materials, and an increase in the Utility's nuclear equipment. The estimated total obligation is decommissioning revenue requirements would reduce the amount of revenues available to 145

offset electric generation costs, and would not The CPUC has authorized the qualified trust to have an impact on the Utility's results of invest a maximum of 50 percent of its funds in operations. publicly traded equity securities, of which up to 20 percent may be invested in publicly traded The CPUC held hearings on the NDCTP in non-US securities. For the nonqualified trust, no September 2002 and is scheduled to issue a final more than 60 percent may be invested in decision in April 2003. publicly traded equities. The trusts are in compliance with the investment restrictions For the year ended December 31, 2002, and authorized by the CPUC.

December 31, 2001, annual nuclear decommissioning trust contributions collected in In general, investment securities are exposed to rates were $24 million and this amount was various risks, such as interest rate, credit, and contributed to the trusts. overall market volatility risks. Due to the level of risk associated with certain investment securities, Amounts contributed to the funds, along with it is reasonably possible that changes in the accumulated earnings, will be used exclusively market values of investment securities could for decommissioning and cannot be released occur in the near term, and such changes could from the trusts until authorized by the CPUC. materially affect the trusts' current value.

Trust fund earnings increase the trust fund balance and the accumulated provision for decommissioning.

146

The following table provides a summary of the amortized cost and fair value, based on quoted market prices, of the Utility's nuclear decommissioning trust funds:  %

Gross Gross Amortized Unrealized Unrealized Estimated (in millions) Maturity Date Cost Gains Losses Fair Value Year ended December 31, 2002 U.S. government and agency issues. 2003-2032 $ 423 $ 50 $ 473 Municipal bonds and other ........... 2003-2034 185 12 (1) 196 Equity securities................. 394 281 (9) 666 Total ........................... $1,002 $343 $(10) 1,335 Other assets ..................... 89 Other liabilities ................... (89)

$00-Fair Value ....................... $1,335 Year ended December 31, 2001 U.S. government and agency issues. 2002-2031 $ 437 $ 39 $ 476 Municipal bonds and other ........... 2002-2034 218 14 (1) 231 Equity securities................. 371 347 (12) 706 Total ........................... $1,026 $400 $(13) 1,413 Other assets ..................... 44 Other liabilities ................... (120)

Fair Value ....................... $1,337 The cost of debt and equity securities sold is estimate for an available site to begin accepting determined by specific identification. The physical possession of the spent nuclear fuel is following table provides a summary of the 2010. At the projected level of operation for activity for the debt and equity securities: Diablo Canyon, the Utility's facilities are able to store on-site all spent fuel produced through Year Ended approximately 2007. It is likely that an interim or (in millions) December 31, permanent DOE storage facility will not be 2002 2001 2000 available for Diablo Canyon's spent fuel by 2007.

Proceeds received from sales of Therefore, the Utility is examining its options for securities .............. $i,631 $751 $1,379 Gross realized gains on sales of providing additional temporary spent fuel storage securities held as available-for- at Diablo Canyon or other facilities.

sale ................. 51 71 74 Gross realized losses on sales of NOTE 14: EMPLOYEE BENEFIT PLANS securities held as available-for-sale ................. 91 98 64 PG&E Corporation and its subsidiaries provide both qualified and nonqualified noncontributory Under the Nuclear Waste Policy Act of 1982, the defined benefit pension plans for their U.S. Department of Energy (DOE) is responsible employees, retirees, and non-employee directors for the permanent storage and disposal of spent (referred to collectively as pension benefits).

nuclear fuel.

PG&E Corporation and its subsidiaries also provide contributory defined benefit medical The Utility has signed a contract with the DOE plans for certain retired employees and their to provide for the disposal of spent nuclear fuel eligible dependents, and noncontributory defined and high-level radioactive waste from the Utility's benefit life insurance plans for certain retired nuclear power facilities. The DOE's current employees (referred to collectively as other 147

benefits). The following schedules aggregate all Pension (in millions) Benefits Other Benefits of PG&E Corporation's plans. All descriptions 2002 2001 2002 2001 and assumptions of the pension benefits and other benefits discussed below are based on the Funded Status Plan assets greater Utility's plans since the Utility's plans represent (lower) than the majority of all plan asset and benefit benefit obligations. obligation .... $ (592) $ 1,088 $ (462) $ (150)

Unrecognized prior The following schedule reconciles the plans' service cost . . . 313 358 13 14 Unrecognized net funded status to the prepaid or accrued benefit (gain) loss. 1,205 (501) 179 (156) cost recorded on the Consolidated Balance Unrecognized net Sheets. The plans' funded status is the difference transition between the fair value of plan assets and the obligation .... 22 36 261 287 benefit obligations. Prepaid (accrued)

Pension benefit cost ... $ 948 $ 981 $ (9) $ (5)

(in millions) Benefits Other Benefits 2002 2001 2002 2001 Utility's share:

Change in Plan assets greater benefit (lower) than obligation benefit Benefit obligation obligation .... $ (553) $ 1,103 $ (448) $ (147) atJanuay I ... $(6,087) $(5,405) $(l,065) $(1,009) Prepaid (accrued)

Service cost for benefit costs ... $ 974 $ 994 $ (11) $ (6) benefits earned (140) (128) (25) (21)

Interest cost ..... (43) (420) (77) (74)

Actuarial loss .... (415) (408) (107) (12) Unrecognized prior service costs and the net Panicipants paid gains are amortized on a straight-line basis over benefits ...... - - (25) (20) the average remaining service period of active Settlement ...... 1 - - - plan participants. The transition obligations for Benefits and expenses paid. 298 274 74 71 pension benefits and other benefits are being

_____ _____ _____ - amortized over 17.5 years from 1987.

Benefit obligation at December 31.. $(6,781) $(6,087) $(0,225) $(1,065)

Change in plan assets Fair value of plan assets at January I. $ 7,175 $ 7,808 $ 915 $ 1,012 Actual return on plan assets .... (690) (364) (149) (70)

Company contributions . . . 10 5 49 27 Plan participant contribution ... - - 25 20 Settlement ...... (8) - - -

Benefits and expenses paid . (298) (274) (77) (74)

Fair value of plan assets at December 31.. $ 6,189 $ 7,175 $ 763 $ 915 148

Net benefit income (cost) was as follows: contributions on a tax-deductible basis to the appropriate trusts.

Pension Benefits Other Benefits (in millons) December 31, December 31, The following actuarial assumptions were used 2002 2001 2000 2002 2001 2000 in determining the plans' assets and benefit Service cost for obligations and net benefit income (cost).

benefits earned $(140) $(128) $(119) $(25) $(21) $(17)

Interest cost .. . (438) (420) (386) (77) (74) (72)

Year-end assumptions are used to compute Expected reMUM on assets and benefit obligations, while prior assets ...... 5.96 645 679 76 83 91 year-end assumptions are used to compute net Amortized prior benefit income (cost).

service and transition cost . (59) (55) (55) (28) (28) (28) Pension Benefits Other Benefits Amortization of Dccember 31, December 31, unrecognized 2002 2001 2000 2002 2001 2000 gain ........ 5 83 183 4 21 32 Setdement (loss) Discount rate..... 6.75% 7.25% 7.50% 6.75% 7.25% 7.50%

gain ........ (7) - 6 - - 18 Average rate of future Benefit income compensation (cost) ...... $.(43) $ 125 S 308 5(50) 5(19) $ 24 increases ...... 5.00 5.00 5.00 5.00 5.00 5.00 Expected return on Utility's share of plan assets ..... 8.10 8.50 8.50 (" 8.50 8.50 benefit income (cost) ....... $ (37) $ 127 $ 302 $(49) 5(19) $ 7 "9 As of the end of 2002, PG&E Corporation changed die expected long-term rate of return on plan assets for various funded plans as follows:

Net benefit income (cost) was calculated using expected return on plan assets of 8.5 percent for Other Benefits:

both pension and other benefits. Defined Benefit - Medical Plan Bargaining 8.500%

Defined Benefit - Medical Plan Management 7.20%

The difference between actual and expected Defined Benefit - Life Insurance Plan 8.10%

return on plan assets is included in net amortization and deferral and is considered in The assumed health care cost trend rate for 2003 the determination of future net benefit income is approximately 10.5 percent, grading down to (cost). The actual return on plan assets was an ultimate rate in 2008 and beyond of below the expected return in 2002, 2001, and approximately 5.5 percent. The assumed health 2000. care cost trend rate can have a significant effect on the amounts reported for health care plans. A Under SFAS No. 71, regulatory adjustments have one-percentage point change would have the been recorded in the Consolidated Statements of following effects:

Operations and Consolidated Balance Sheets of the Utility to reflect the difference between 1-Percentage 1-Percentage Utility pension income for accounting purposes (In millions) Point Increase Point Decrease and Utility pension income for ratemaking, Effect on total service which is based on a funding approach. The and interest cost CPUC has authorized the Utility to recover the components ..... $8 $ (7)

Effect on post costs associated with its other benefits for 1993 retirement benefits and beyond. Recovery is based on the lesser of obligation ...... $72 $(67) the annual accounting costs or the annual 149

Defined Contribution 401(k) Benefits stock appreciation rights and dividend equivalents.

PG&E Corporation and its subsidiaries also sponsor defined contribution pension plans more At December 31, 2002, 45,527,595 shares of commonly referred to as 401(k) plans. These PG&E Corporation common stock had been plans are qualified under applicable sections of authorized for award under the SOP, with the Internal Revenue Code. These plans provide 14,507,614 shares still available under the SOP.

for tax-deferred salary deductions and after-tax employee contributions as well as employer PG&E Corporation - Consolidated contributions. Employees designate the funds in which their contributions and any employer Fair values of options granted in 2002, 2001, and contributions are invested. Employer 2000 under the Black-Scholes valuation method contributions include matching and/or basic are as follows:

contributions. For certain plans, matching (1) Options granted in 2002 had weighted employer contributions are automatically average fair value under the Black-Scholes invested in PG&E Corporation common stock.

valuation method of $6.61 per share for Employees may reallocate matching employer 211,712 shares; contributions and accumulated earnings thereon to another investment fund or funds available to (2) Options granted in 2001 were measured their plan at any time once they have been using two sets of assumptions deriving credited to their account. Employee contribution weighted average fair values of $6.01 per expense reflected in the accompanying PG&E share for 5,736,300 options granted and Corporation's Consolidated Statements of $5.80 per share for 5,670,852 options Operations amounted to: granted at their respective date of grant; and (in millions) (3) Options granted in 2000 had weighted Year ended December 31, Amounts average fair values at their date of grant of

$3.26.

2002 $52 2001 48 2000 60 Significant assumptions used in the Black-Scholes valuation method for shares granted in 2002, Long-Term Incentive Program 2001 (two sets of assumptions), and 2000 were:

2002 2001 2000 PG&E Corporation maintains a Long-Term Incentive Program (Program) that permits various Expected stock price 33.00% &

volatility ......... 30.0% 29.05% 20.19%

stock-based incentive awards to be granted to Expected dividend yield . 0% &

non-employee directors, executive officers, and 0% 4.35% 5.18%

other employees of PG&E Corporation and its Risk-free interest rate ... 5.24% &

subsidiaries. The Stock Option Plan, the 4.65% 5.95% 6.10%

Performance Unit Plan, and the Non-Employee Expected life ........ 10 years 10 years 10 years Director Stock Incentive Plan (each of which is a component of the Program) provide incentives Outstanding stock options become exercisable based on PG&E Corporation's financial on a cumulative basis at one-third each year performance over time. commencing two years from the date of grant and expire ten years and one day after the date Stock Option Plan (SOP) of grant. Options outstanding at December 31, 2002, had option prices ranging from $11.80 to The SOP provides for grants of stock options to $34.25, and a weighted average remaining eligible participants with or without associated contractual life of 6.5 years.

150

The following table summarizes the consolidated SOPs activity at and for the years ended December 31:

(shares in millions) 2002 2001 2000 Weighted Weighted WeIghted Average Average Average Shares Option Price Shares Option Price Shares Option Price Outstanding, beginning of year .......... 34.1 $22.11 24.3 $25.90 16.4 $29.42 Granted during year .................. 0.2 19.44 11.4 14.33 10.2 20.03 Exercised during year ................. (0.3) 23.65 (0.1) 31.96 (1.2) 23.52 Cancellations during year .............. (2.9) 27.61 (1.5) 23.55 (1.1) 26.57 Outstanding, end of year............... 31.1 22.22 34.1 22.11 24.3 25.90 Exercisable, end of year ............... 15.5 27.05 10.9 27.86 6.3 27.73 The following summarizes information for 2000 under the Black-Scholes valuation method, options outstanding and exercisable at using the same assumptions as above, are as December 31, 2002. Of the outstanding options follows:

at December 31, 2002:

(1) No options were granted in 2002; (1) 203,712 options had exercise prices ranging (2) Options granted in 2001 were measured from $17.35 to $21.07 with a weighted using two sets of assumptions deriving average remaining contractual life of weighted average fair values of $6.01 per 9.04 years, of which none of the shares share for 2,057,500 options granted and were exercisable;

$5.80 per share for 2,054,100 options (2) 9,974,652 options had exercise prices granted at their respective date of grant; and ranging from $9.75 to $19.56, with a (3) Options granted in 2000 had weighted weighted average remaining contractual life average fair values at their date of grant of of 8.3 years, of which 189,700 shares were

$3.26.

exercisable at a weighted average exercise price of $14.21; and In general, outstanding stock options become (3) 7,826,604 options had exercise prices exercisable on a cumulative basis at one-third ranging from $19.81 to $29.06, with a each year commencing two years from the date weighted average remaining contractual life of grant and expire ten years and one day after of 6.8 years, of which 3,538,779 shares were the date of grant.

exercisable at a weighted average exercise price of $19.96. Options outstanding at December 31, 2002, had option prices ranging from $12.63 to $34.25, and In addition, 3,593,775 options were granted on a weighted average remaining contractual life of January 2, 2003, at an exercise price of $14.61, 7.4 years.

the then-current market price of PG&E Corporation common stock.

Utility Fair values of options granted to purchase PG&E Corporation common stock in 2002, 2001, and 151

The following table summarizes the SOPs activity for the Utility at and for the years ended December 31:

(shares in millions) 2002 2001 2000 Weighted Weighted Weighted Average Average Average Shares Option Price Shares Option Price Shares Option Price Outstanding, beginning of year.... 12.7 $22.40 8.9 $26.31 6.8 $29.25 Granted during year ........... 4.1 14.32 3.3 19.89 Exercised during year .......... (0.2) 23.60 (0.1) 31.96 (0.8) 24.81 Cancellations during year ........ (0.1) 23.73 (0.2) 24.44 (0.4) 26.95 Outstanding, end of year ........ 12.4 22.37 12.7 22.40 8.9 26.31 Exercisable, end of year......... 5.9 27.74 4.0 28.81 4.0 28.98 The following summarizes information for Nfon-Employee DirectorStock Incentive Plan options outstanding and exercisable at (NEDSIP)

December 31, 2002. Of the outstanding options at December 31, 2002: Under the NEDSIP, each person who is a non-employee director on the first business day (1) 4,045,600 options, related to 2001 grants had of the applicable calendar year is entitled to exercise prices ranging from $12.63 to receive stock-based grants with a total aggregate

$16.01, with a weighted average remaining equity value of $30,000, composed of:

contractual life of 9.3 years, of which 60,800 options were exercisable at a weighted (1) Restricted shares of PG&E Corporation average exercise price of $13.57; and common stock valued at $10,000 (based on the closing price of PG&E Corporation (2) 2,921,124 options, related to 2000 grants, common stock on the first business day of had exercise prices ranging from $19.81 to the year); and

$26.31, with a weighted average remaining contractual life of 8.0 years, of which (2) A combination of non-qualified stock 1,009,499 options were exercisable at a options and common stock equivalents with weighted average exercise price of $19.90. a total equity value of $20,000 based on equity value increments of $5,000.

In addition, 2,029,725 options were granted on January 2, 2003, at an exercise price of $14.61, The exercise price of stock options is equal to the then-current market price of PG&E the fair market value of PG&E Corporation Corporation common stock. common stock on the date of grant. Restricted stock and stock options vest over a five-year PerformanceUnit Plan (PUP) period following the date of grant except:

(1) Upon a director's mandatory retirement from Under the PUP, PG&E Corporation grants the Board; performance units to certain officers of PG&E Corporation and its subsidiaries. The (2) Upon a director's death or disability; or performance units vest one-third in each of the (3) In the event of a change in control, in three years following the year of grant. The which cases the restricted stock and stock number of performance units granted and the options will vest immediately.

amount of compensation expense recognized in connection with the issuance of performance The component of the NEDSIP representing units during the years ended December 31, 2002, stock options at December 31, 2002, 2001, and 2001, and 2000, were not material.

2000, is included in the above data under SOP in accordance with APB No. 25 and SFAS No. 123, as amended by SFAS No. 148. The component of 152

the NEDSIP representing expense recognized in Executive Stock Ownersbip Program connection with issuance of restricted stock and (ESOP) common stock equivalents during the years ended December 31, 2002, 2001, and 2000, was The ESOP sets certain stock ownership targets not material. for certain employees. The targets are set as a multiple of the employee's base salary and vary PG&E CorporationSupplemental Retirement according to the employee. To the extent an Savings Plan (SRSP) employee achieves and maintains the stock ownership targets, the employee will be entitled The SRSP provides supplemental retirement to receive additional common stock equivalents alternatives to eligible senior officers and key called Special Incentive Stock Ownership employees of PG&E Corporation and its Premiums (SISOPs) to be credited to his or her subsidiaries by allowing participants to defer SRSP account. The SISOPs vest three years after portions of their compensation, including the date of grant and are subject to forfeiture if salaries, amounts awarded under the PUP, and the employee fails to maintain his or her other incentive awards. The SRSP also provides a respective stock ownership target. The amount of means for eligible participants to receive and expense related to SISOPs granted including the invest employer contribution amounts exceeding net of appreciation and depreciation on the contribution limits within the various defined stock price of PG&E Corporation common stock contribution plans sponsored by PG&E for the years ended December 31, 2002, 2001, Corporation and its subsidiaries. Under the and 2000, was not material.

employee-elected deferral component of the SRSP, eligible employees may defer all or part of Restricted Stock Awards their PUP (if eligible) and other incentive awards, and 5 to 50 percent of their monthly In January 2003, PG&E Corporation awarded salary each month. Under the supplemental restricted shares of PG&E Corporation common employer-provided retirement benefits stock to eligible employees of PG&E Corporation component of the SRSP, eligible employees and its subsidiaries. The shares are granted with receive full employer matching and basic restrictions and are subject to forfeiture unless contributions in excess of limitations set out by certain conditions are met. On January 2, 2003, the Internal Revenue Code as qualified under 1.6 million shares of restricted stock were defined contribution 401(k) plans into a granted.

non-qualified account. A separate non-qualified account is maintained for each eligible employee The restricted shares are issued at the grant date to hold any deferred and/or employer- and are held in an escrow account. The shares contributed amounts with investment options become available to the employees as the available for the employee's designation. PG&E restrictions lapse. In general, the restrictions Corporation recognizes any gain or loss from lapse automatically over a period of four years at these investments and adjusts each employee the rate of 20 percent per year, restrictions as to account on a quarterly basis. Expense related to an additional 5 percent of the shares will lapse deferred amounts is recognized in the period in per year if PG&E Corporation is in the top which it is earned by the employee and accrued quartile of its comparator as measured by until paid under the terms of the plan. Employer relative annual total shareholder return for years contribution expense and expenses related to ending immediately before each annual lapse gain or loss from investments of contributed and date.

deferred amounts recognized in connection with the SRSP during the years ended December 31, Retention Programs 2001, and 2000, was not material. For the year ended December 31, 2002, the expense PG&E Corporation implemented various amounted to $3 million. retention mechanisms in 2001. These mechanisms awarded identified key personnel of 153

PG&E Corporation and its subsidiaries with in 2001. The phantom stock units are lump-sum cash payments and/or units of Special marked-to-market based on the market price of Senior Executive Retention Grants. PG&E Corporation common stock, and amortized as a charge to income over a four-year period.

The Special Senior Executive Retention Grants The expense recognized in connection with provide certain employees with phantom PG&E these retention mechanisms, including cash Corporation restricted stock units that, except in payments and phantom restricted stock units the event of a change in control, or on the totaled $12 million for the year ended employee's death or disability, vest no earlier December 31, 2002, and $29 million for the year than December 31, 2003. Vesting of one half of ended December 31, 2001.

the awards is also dependent upon meeting certain performance measures. NOTE 15: INCOME TAXES The number of units of phantom stock granted The significant parts of income tax (benefit) under these mechanisms totaled 3,044,600 units expense for continuing operations were:

(In millons) PG&E Corporation Utility Year Ended December 31, 2002 2001 2000 2002 2001 2000 Current . ............................ $ 478 $ 967 $(1,284) $ 838 $ 902 $(1,224)

Deferred . ............................ (510) (393) (780) 351 (267) (891)

Tax credits, net ........................ (11) (39) (39) (11) (39) (39)

Income tax (benefit) expense .... ....... $ (43) $ 535 $(2,103) $1,178 $ 596 $(2,154)

The following details net deferred income tax liabilities:

PG&E (in millions) Corporation Utility Year ended December 31, 2002 2001 2002 2001 Deferred income tax assets:

Customer advances for construction ...................... $ 318 $ 252 $ 318 $ 252 Unamortized investment tax credits ....................... 105 110 105 110 Reserve for damages ................................. 268 254 268 254 Environmental reserve ................................ 162 161 162 161 ISO energy purchases ................................ 353 353 Impairments ....................................... 1,162 Other ............................................ 244 336 79 217 Total deferred income tax assets ...................... $2,259 $ 1,466 $ 932 $1,347 Deferred income tax liabilities:

Regulatory balancing accounts .......................... $ 175 $ 369 $ 175 369 Property related basis differences ........................ 2,220 2,085 1,778 1,665 Income tax regulatory asset ............................ 134 83 134 83 Other ............................................ 517 481 325 323 Total deferred income tax liabilities .................... 3,046 3,018 2,412 2,440 Total net deferred Income taxes liabilities ............... 787 1,552 1,480 1,093 Classification of net deferred income taxes liabilities:

Included in current liabilities. ........................... 4 73 (5) 65 Included in noncurrent liabilities ......................... 783 1,479 1,485 1,028 Total net deferred income taxes liabilities ............... $ 787 $ 1,552 $1,480 $1,093 154

The differences between income taxes and amounts calculated by applying the federal legal rate to income before income tax expense for continuing operations were:

($ dollars in millions) PG&E Corporation Utility Year Ended December 31, 2002 2001 2000 2002 2001 2000 Federal statutory income tax rate ............... 35.0/a%35.0%/ 35.0% 35.0% 35.0% 35.0%

Increase (decrease) in income tax rate resulting from:

State income tax (net of federal benefit) ........ (45.5) 4.7 4.5 5.4 5.0 4.3 Effect of regulatory treatment of depreciation differe (34.4) 1.8 (2.0) 1.2 1.7 (2.0)

Tax credits, net .......................... 83.8 (4.3) 0.7 (0.6) (2.5) 0.7 Effect of foreign earnings at different tax rates .... (15.6) (0.1) 0.1 - - -

Stock sale differences ...................... (1.4) _ _

Stock sale valuation allowance ............... _ - 1.5 Other, net .............................. 20.0 (1.8) (0.3) (1.7) (2.3) 0.1 Effective tax rate ........................... 43.3% 35.3% 38.1% 39.3% 36.9%o 38.1%

At December 31, 2002, PG&E Corporation had it is more likely than not that these deferred tax

$420 million of California net operating loss benefits will be realized on a consolidated basis.

(NOL) carryforwards that will expire if not used by the end of 2012. The California Revenue and NOTE 16: COMMITMENTS AND Taxation Code has suspended the use of NOL CONTINGENCIES cariyforwards for the tax years ending December 31, 2002, and December 31, 2003. Conmmitments In 2002, PG&E Corporation established valuation PG&E Corporation has substantial financial allowances for state deferred tax assets commitments in connection with agreements associated with PG&E NEG's impairments and entered into supporting the Utility's and PG&E write-offs. A valuation allowance of $97 million NEG's operating, construction, and development was recorded in continuing operations with activities. PG&E NEG's commitments are respect to these state deferred tax assets. In discussed in Note 3.

addition, a valuation allowance of $87 million was recorded in discontinued operations with UtiY respect to state deferred tax assets associated with impairments and write-offs reflected in Natural Gas Supply and Transportation discontinued operations. These valuation Commitments - The Utility purchases natural allowances were established due to the gas directly from producers and marketers in uncertainty in realizing tax benefits associated both Canada and the United States. The with the state deferred tax assets. PG&E composition of the portfolio of natural gas Corporation could not determine that it was procurement contracts has fluctuated, generally more likely than not that some portion or all of based on market conditions.

its state deferred tax assets would be realized.

The Utility also has long-term gas transportation In addition to the reserves above, PG&E NEG service agreements with various Canadian and recorded additional valuation reserves on a interstate pipeline companies. These companies stand-alone basis for federal deferred tax assets are responsible for transporting the Utility's gas of $408 million related to continuing operations to the California border. The total demand and $381 million related to discontinued charges that the Utility will pay each year may operations. These reserves were eliminated in change due to changes in tariff rates. These consolidation, as PG&E Corporation believes that agreements include provisions for payment of 155

fixed demand charges for reserving firm pipeline Power Purcbase Agreements capacity as well as volumetric transportation charges. The total demand and volumetric Qualiying Facilities - The Utility is required transportation charges the Utility incurred under by CPUC decisions to purchase energy and these agreements were $101 million in 2002, capacity from independent power producers that

$239 million in 2001, and $94 million in 2000. are qualifying facilities, or QFs, under the Public Utility Regulatory Policies Act of 1978, or PURPA.

At December 31, 2002, the Utility's obligations Pursuant to PURPA, the CPUC required California for natural gas purchases and gas transportation utilities to enter into a series of long-term power services are as follows: purchase agreements, or PPAs, with QFs and approved the applicable terms, conditions, price (in mlons) options and eligibility requirements. The PPAs 2003 ......... . . . . .. . . . . $595 with QFs require the Utility to pay for energy 2004 ......... . . . . .. . . . . 138 2005 ......... . . . . .. . . . . 83 and capacity. Energy payments are based on the 2006 ......... . . . . . . I . . . 26 QFs actual electrical output and CPUC-approved 2007 ......... . . . . . . . . . . 10 Thereafter ..... . . . . . .

energy prices, while capacity payments are based Total ........

on the QFs total available capacity and

$852 contractual capacity commitment. Capacity payments may be reduced or increased if the Since the Utility filed for bankruptcy and its facility fails to meet or, alternatively, exceeds credit rating is below investment grade, the performance requirements specified in the Utility uses several different credit arrangements applicable PPAs. The Utility recovers its costs for the purpose of purchasing natural gas. The incurred from these contracts through electric Utility has a $10 million standby letter of credit revenues billed to the customers. Most of the and pledges its gas customer accounts PPAs with QFs expire on various dates through receivable. The core gas inventory will be 2028. The Utility's PPAs with QFs accounted for pledged only if the Utility's gas customer approximately 25 percent of the 2002 electricity accounts receivable are less than the amount that deliveries and approximately 21 percent of the the Utility owes to the gas suppliers. As of 2001 electricity deliveries. There was no single December 31, 2002, the accounts receivable agreement that accounted for more than were sufficient. Therefore, the core gas inventory 5 percent of the Utility's electricity deliveries in has not been pledged. The CPUC authorized the 2002 or 2001.

Utility to pledge its gas accounts receivable and core inventory, if necessary, until the earlier of: As a result of the energy crisis and the Utility's

• May 1, 2003; or bankruptcy filing, a number of QFs requested the Bankruptcy Court to either (1) terminate their

• 15 days after an upgrade of the credit contracts requiring them to sell power to the rating of the Utility's mortgage bonds to at Utility, or (2) have the contracts suspended for least BBB- by S&P or Baa3 by Moody's; or the summer of 2001 so the QFs could sell power

• The effective date of a plan of at market rates to the Utility. The Bankruptcy reorganization; or Court ordered the QFs to directly negotiate with the Utility. In July 2001, 197 QFs elected to

• The dismissal or conversion of the Utility's adopt CPUC-approved amendments to their PPAs bankruptcy proceeding. to fix their energy payments at $0.054 per kWh for five years.

At December 31, 2002, the pledged amount for total gas accounts receivable was $513 million. In December 2001, the Bankruptcy Court approved supplemental agreements between the Utility and most QFs to resolve the applicable interest rate to be applied to pre-petition amounts owed to QFs. The supplemental 156

agreements (1) set the interest rate for purchasing power. Several of these contracts pre-petition payables at 5 percent, (2) provide were terminated by the other parties because for a "catch-up payment" of all accrued and either the Utility filed for bankruptcy or the unpaid interest through the initial payment date, Utility's credit rating declined to below and (3) depending on the amount owed, provide investment grade. As stated in the contracts, the for either (a) payment of the principal and contracts must be settled at the market value on interest amount of the pre-petition payable, or the termination date. The estimated (pre-tax) net (b) payment in 6 or 12 monthly payments gain on the terminated contracts of $552 million beginning on the last business day of the month in 2001 was used to reduce the cost of electricity during which the Bankruptcy Court approval was in the Utility's and PG&E Corporation's granted. In the event the effective date of a plan Consolidated Statements of Operations.

of reorganization occurs before the last monthly payment is made, the remaining unpaid principal At December 31, 2002, the Utility had and unpaid interest shall be paid on the effective outstanding two bilateral forward electric date. The total amount the Utility owed to QFs contracts, which will expire in 2003. The when it filed for bankruptcy protection was undiscounted future minimum energy payments approximately $1 billion. The principal payments due under these contracts are $196 million in to the QFs amounted to $901 million in 2002 and 2003. Under the normal purchases and sales the interest payments amounted to $44 million in accounting exemption of SFAS No. 133, the 2002 and $16 million in 2001. Utility does not recognize the cost of the bilateral contracts until the energy is delivered. At Through December 31, 2002, 264 of 313 QFs December 31, 2002, the outstanding bilateral have signed assumption and/or supplemental contracts have an estimated negative market agreements. The Utility believes it will be able to value of $36 million. This value would be enter into similar supplemental agreements with recorded as a cost of electricity in the some of the remaining QFs. Consolidated Statements of Operations if these contracts failed to meet the normal purchases IrrigationDistricts and Water and sales exemption. The provisions of one of Agencies - The Utility has contracts with various the contracts allows the other party to terminate irrigation districts and water agencies to purchase the contract without penalty at fair value while hydroelectric power. Under these contracts, the the Utility is in a Chapter 11 bankruptcy filing.

Utility must make (1) specified semi-annual The Utility expects that the physical delivery of minimum payments based on the irrigation electricity will continue through the duration of districts' and water agencies' debt service the contract period and that the contracts will requirements, whether or not any energy is continue to meet the normal purchases and sales supplied (subject to the supplier's retention of exemptions.

the FERC's authorization), and (2) variable payments for operation and maintenance costs Other- California Senate Bill 1078, or SB 1078, incurred by the suppliers. These contracts expire requires private utilities to increase their on various dates from 2004 to 2031. The Utility's renewable energy supplies by 1 percent a year PPAs with irrigation districts and water agencies until these supplies are 20 percent of their accounted for approximately 4 percent of the generation supply portfolio, provided sufficient 2002 electricity deliveries and accounted for funds are available to cover any above-market approximately 3 percent of the 2001 electricity costs of renewables. Utilities must meet the deliveries. 20 percent of their generation supply portfolio no later than 2017.

BilateralPower PurchaseContracts- Despite the lack of established criteria for cost recovery In November 2002, the Utility entered into four from the CPUC, the Utility entered into several contracts with renewable energy suppliers that bilateral forward electric contracts in would obligate the Utility and the DWR upon the October 2000 to stabilize the escalating costs of occurrence of certain conditions. Subsequently, 157

in February 2003, one of the contracts was contracts in the first year or until the Utility terminated. The terms of these contracts with the attains an investment grade credit rating, renewable energy suppliers are for five years whichever comes first. The Utility has proposed commencing on or after January 1, 2003. The to recover the costs of these contracts through its Utility will reimburse the DWR for the cost of the Energy Resource Recovery Account.

The amount of energy received and the total payments made under QF, irrigation district and water agency, and bilateral PPAs were as follows:

(in millions, except Year ended pg9awan-hours) December 31,I 200:2 2001 2000 Gigawatt-hours received ................................................ 28,OF 88 23,732 26,027 QF Energy payments ...............  : Ai $1,454 $1,549 QF Capacity payments ................................................

$1s016 473 519 Irrigation district and water agency payments ................................... 57 54 56 Bilateral payments .................................................... 96 155 53 At December 31, 2002, the undiscounted future expected PPA payments are as follows:

Irrigation Disuict QF &Water Agency Bilateral Other Operations & Debt (in Millions) Energy Capacity Maintenance Service Eno rgy Energy Capacity Total 2003 .. .... $1,150 $ 530 $ 38 $ 28 $1' %6 $ 14 $ 28 $ 1,984 2004 .. 10....

,80 520 31 28 - 14 28 1,701 2005 . .... 960 490 26 26 - 14 28 1,544 2006 . .... 880 470 27 27 - 14 28 1,446 2007 . .... 830 450 28 27 - 14 28 1,377 Thereafter ..... 5,000 2,800 524 168 - - - 8,492 Total . .... $9,900 $5,260 $674 $304 $1!96 $ 70 $140 $16,544 WAPA Sales Contract Commitments - In 1967, been presumed when the contract was executed.

the Utility and the Western Area Power As a result, during the energy crisis, the Utility Administration, or WAPA, entered into a paid substantially more for the electricity it long-term power contract governing (1) the purchased on behalf of WAPA than it received interconnection of the Utility's and WAPA's for the sales of electricity to WAPA.

transmission systems, (2) the use of the Utility's The costs going forward to procure power to transmission and distribution system by WAPA, fulfill the Utility's obligations to WAPA under the and (3) the integration of the Utility's and contract is uncertain. However, the Utility WAPA's loads and resources. The contract gave expects that the cost of meeting its obligation to the Utility access to surplus hydroelectric power WAPA may be greater than the price the Utility at low prices and obligated the Utility to provide receives from WAPA under the contract. Under WAPA with electricity when its own resources AB 1890, the Utility's retail ratepayers pay for were not sufficient to meet its requirements. The this difference as a stranded power purchase contract terminates on December 31, 2004.

cost. The amount of the difference between the As a result of California's electric industry Utility's cost to meet its obligations to WAPA and restructuring in 1998, the Utility was required to the revenues it receives from WAPA cannot be procure the energy it needed to meet its own accurately estimated at this time since both the and WAPA's requirements from the Power purchase price and the amount of electricity Exchange. This caused the Utility to be exposed WAPA will need from the Utility through the end to market-based electric pricing rather than the of the contract are uncertain. Though it is not cost of service-based electric pricing that had indicative of future sales commitments or sales-158

related costs, WAPA's net amount purchased At December 31, 2002, the approximate from the Utility is 3,619 GWh in 2002, 4,823 obligations under these operating lease GWh in 2001, and 5,120 GWh in 2000. agreements are as follows:

(in mSons)

Nuclear Fuel Agreements - The Utility has purchase agreements for nuclear fuel 2003 ....................... ........ $9 2004 ....................... ........ .....10 components and services for use in operating the 2005 ....................... ........ ..... 9 Diablo Canyon generating facility. These 2006 ....................... ........ ..... 9 agreements run from two to five years and are 207 ....................... ........ .... 9 intended to ensure long-term fuel supply, but Thereafter .................... .. . . . . . . .. 9 also permit the Utility the flexibility to take Total ....................... ........ ...$55 advantage of short-term supply opportunities.

Deliveries under six of the eight contracts in The operating expenses related to the operating place at the end of 2002 will end by 2005. In lease agreements for office space amounted most cases, the Utility's nuclear fuel contracts are $13 million in 2002, $11 million in 2001, and requirements-based and dependent on the $12 million in 2000.

Utility's continued operation of its Diablo Canyon generating plant. Otber Commitments At December 31, 2002, the undiscounted CapitalInfusion Agreement - The Utility has obligations under nuclear fuel agreements are as entered into Capital Infusion Agreements, which follows: obligate the Utility to make scheduled payments to investment partnerships in return for a limited (in ndlons) partnership interest. The CPUC has approved the 2003 ..... , ... 59

,$,.. Utility's investment in the non-regulated 2004...................... .... 50 2005 ...... . . ... 12 subsidiaries, which are mainly engaged in the 2006............................ 13 purchase of residential real estate property. The 2007 ....... , ...... 14 Capital Infusion agreements are secured by the Thereafter .65 Utility's interest in the partnership and the Utility Total .$................. 5213 is fully responsible for its future obligations under these agreements. See discussion of Payments for nuclear fuel amounted to unconsolidated subsidiaries in Note 1.

$70 million in 2002, $50 million in 2001, and Under the agreements, the Utility is in default if

$78 million in 2000.

the Utility (1) becomes insolvent or files for The Utility relies on large, well-established bankruptcy, or (2) fails to make any of its international producers for its long-term scheduled payments. While technically in default agreements in order to diversify its commitments as of December 31, 2002, the Utility is current on and ensure security of supply. Pricing terms are all its payments and expects to make all future also diversified, ranging from fixed prices to base payments when they become due. The Utility prices that are adjusted using published believes the technical default will not result in a information. loss in the Utility's investment interest.

Operating Leases The Utility's contributions to the investment partnership amounted to $7 million in 2002, The Utility has entered into several operating

$9 million in 2001, and $4 million in 2000.

lease agreements for office space. The leases expire on various dates between 2003 and 2009. Diablo Canyon Power-PlantTurbines - The Utility has entered into a contract to retrofit its six low-pressure turbines at Diablo Canyon Unit 1 and Unit 2. These turbine retrofits will (1) improve reliability of the turbine equipment, (2) reduce maintenance costs, and (3) produce more electricity through improved efficiency. The 159

installation of the turbine retrofits is expected to investment in these programs, and the CPUC has begin in Fall 2005. Progress payments for the not addressed how these costs will be recovered.

turbines will begin in 2003 as certain milestones See discussion of the Utility's policy regarding are reached. The Utility expects all costs incurred balancing accounts in Note 1.

under the contract to be capitalized, and Telecomnmunications - The Utility has several included in Property, Plant, and Equipment in cancelable contracts to support the Utility's local the Consolidated Balance Sheets and amortized and long-distance telecommunication needs. The over the useful life of the asset.

terms of the contracts require the Utility to give a Self-Generation Incentive Program- The one-year notice in order to terminate the service.

CPUC directed the state's larger investor-owned Therefore, the Utility's future commitment is the utilities to fund load-control and self-generation annual amount, less any amount already paid.

initiatives at an annual cost of $138 million for The costs incurred under these contracts four years beginning in 2001. The Utility's amounted to $7 million in 2002, $9 million in portion of the annual costs is $3 million for load 2001, and $5 million in 2000.

control and $60 million for self-generation initiatives per year. Under the self-generation At December 31, 2002, the future minimum incentive portion, the Utility offers lump sum payments related to other commitments as rebates to customers who install up to one- described above are as follows:

and-a-half megawatts of "clean" on-site (in minions) distributed energy. As of December 31, 2002, the 2003 ............................... $ 51 Utility has signed contracts with 54 customers. 2004 ............................... 35 The Utility's estimated obligation under these 2005 ............................... 30 contracts is $16 million. The Utility expects the 2006 ............................... 15 2007 ............................... 2 majority of the contract obligations to be fulfilled Thereafter ........................... 2 in 2003 and payment obligations to be paid to the customers. However, customers have the Total .............................. $135 option of extending the installment date by up to another 180 days due to unforeseen events (such PG&E NEG as delays in equipment arrival, delays in PG&E NEG, through its subsidiaries, has entered permitting process, etc.), which would in turn into various long-term firm commitments. PG&E delay the incentive payments. NEG and its subsidiaries are negotiating with the The costs associated with the incentive portion lenders, debtholders and other counterparties in of the self-generation program amounted to an attempt to restructure these commitments.

$7 million in 2002 with no similar costs incurred The ability of PG&E NEG and its subsidiaries to in 2001 and 2000. fund these commitments depends on the terms of any restructuring plan that may be agreed to The CPUC has stated that it will allow costs of by the appropriate parties. The following table this program which are not recovered during the identifies by year, the aggregate amounts of rate freeze to be recorded in a balancing account these commitments:

and recovered after the rate freeze ends. The Utility receives no rate of return on its (in millions) 2003 2004 2005 2006 2007 Thereafter TOTAL Fuel Supply and Transportation Agreements ..... ........... $ 105 $ 91 $ 91 $ 88 $ 75 $ 380 $ 830 Power Purchase Agreements .............. ........... 217 220 220 220 225 1,140 2,242 Operating Leases ..................... ........... 70 79 79 81 84 807 1,200 Long Term Service Agreements ............. ........... 41 7 7 7 7 36 105 Payments in Lieu of Taxes ................ ........... 28 21 14 16 17 97 193 Construction Commitments ............... ........... 237 237 Tolling Agreements .................... 62 62 62 62 62 482 792 160

Fuel Supply and Transportation generating plants. These agreements are for Agreements - PG&E NEG, through various periods up to 18 years.

subsidiaries, has entered into gas supply and firm transportation agreements with various Payments in Lieu of Property pipelines and transporters to provide fuel Taxes - Various subsidiaries of PG&E NEG have transportation services. Under these agreements, entered into certain agreements with local PG&E NEG must make specified minimum governments that provide for payments in lieu of payments each month. property taxes for some of its generating facilities.

Power PurcbaseAgreements - USGenNE assumed rights and duties under several power Construction Commitments - Various purchase contracts with third party independent subsidiaries of PG&E NEG currently have power producers as part of the acquisition of the projects (Athens, Covert, La Paloma, and New England Electric System (NEES) assets. As Harquahala) under construction. PG&E NEG's of December 31, 2002, these agreements construction commitments are generally related provided for an aggregate of approximately 800 to the major construction agreements including MW of capacity. USGen New England is required the construction and other related contracts.

to pay to New England Power Company Certain construction contracts also contain amounts due to third-party producers under the commitments to purchase turbines and related power purchase contracts. equipment.

OperatingLeases - Various subsidiaries of Tolling Agreements PG&E NEG have entered into several operating lease agreements for generating facilities and PG&E ET, entered into tolling agreements with office space. Lease terms vary between 3 and several counterparties under which it, at its 48 years. discretion, supplies the fuel to the power plants and then sells the plant's output in the In November 1998, USGenNE entered into a competitive market. Payments to counterparties

$479 million sale-leaseback transaction whereby are reduced if the plants do not achieve the subsidiary sold and leased back a pumped agreed-upon levels of performance. The face storage station under an operating lease. amount of PG&E NEG's and its subsidiaries' guarantees relating to PG&E Ers tolling On May 7, 2002, Attala Generating Company agreements is approximately $600 million. The LLC, an indirect subsidiary of PG&E NEG, tolling agreements currently in place are with completed a $340 million sale and leaseback (1) Liberty Electric Power, L.P. (Liberty) transaction whereby it sold and leased back its guaranteed by both PG&E NEG and PG&E GTN facility to a third party special purpose entity. for an aggregate amount of up to $150 million; The related lease is being accounted for as an (2) DTE-Georgetown, LLC (DTE) guaranteed by operating lease. See Note 7 "Impairments, Write- PG&E GTN for up to $24 million; (3) Calpine offs, and Other Charges". Energy Services, L.P. (Calpine) for which no guarantee is in place; (4) Southaven Power, LLC Operating lease expense amounted to (Southaven) guaranteed by PG&E NEG for up to

$78 million, $54 million, and $70 million in 2002, $175 million; and (5) Caledonia Generating, LLC 2001, and 2000, respectively. (Caledonia) guaranteed by PG&E NEG for up to

$250 million.

Long Term Service Agreements - Various subsidiaries of PG&E NEG have entered into Liberty - Liberty has provided notice to PG&E long-term service agreements for the ET that the ratings downgrade of PG&E NEG maintenance and repair of certain of its constituted a material adverse change under the combustion turbine or combined-cycle tolling agreement requiring PG&E ET to replace the guarantee and to post security in the amount 161

of $150 million. PG&E ET has not posted such default under the agreement, but has not taken security. Liberty has the right to terminate the any further action.

agreement and seek recovery of a termination payment. Under the terms of the guarantees to Caledonia and Soutbaven Toling Liberty for the aggregate $150 million, Liberty Agreements. - PG&E ET signed a tolling must first proceed against PG&E NEG's agreement with Southaven Power, LLC guarantee, and can demand payment under (Southaven) dated as of June 1, 2000, under PG&E GTN's guarantee only if (1) PG&E NEG is which PG&E ET is required to provide credit in bankruptcy or (2) Liberty has made a payment support as defined in the tolling agreement.

demand on PG&E NEG which remains unpaid PG&E ET satisfied this obligation by providing five business days after the payment demand is an investment-grade guarantee from PG&E NEG made. In addition, PG&E ET has provided as defined in the tolling agreement. The amount notices to Liberty of several breaches of the of the guarantee as of January 31, 2003 does not tolling agreement by Liberty and has advised exceed $175 million. By letter dated August 31, Liberty that, unless cured, these breaches would 2002, Southaven advised PG&E ET that it constitute a default under the agreement. If these believed an event of default under the tolling defaults remain uncured, PG&E ET has the right agreement had taken place with respect to this to terminate the agreement and seek recovery of obligation as PG&E NEG was no longer a termination payment. investment-grade as defined in the tolling agreement and because PG&E ET had failed to DTE - By letter dated October 14, 2002, DTE provide, within thirty days from the downgrade provided notice to PG&E ET that the downgrade substitute credit support that met the of PG&E GTN constituted a material adverse requirement of the agreement. Southaven has the change under the tolling agreement between right to terminate the agreement and seek a PG&E ET and DTE and that PG&E ET was termination payment. In addition, PG&E ET has required to post replacement security within ten provided Southaven with a notice of default days. By letter dated October 23, 2002, PG&E ET respecting Southaven's performance under the advised DTE that because there had not been a tolling agreement concerning the inability of the material adverse change with respect to PG&E facility to inject its output into the local grid.

GTN within the meaning of the tolling Southaven has not cured this default and on agreement, PG&E ET was not required to post February 4, 2003, PG&E ET provided a notice of replacement security. If PG&E ET was required termination.

to post replacement security and it failed to do so, DTE would have the right to terminate the PG&E ET signed a tolling agreement with tolling agreement and seek recovery of a Caledonia Generating, LLC (Caledonia) dated as termination payment. of September 20, 2000, under which PG&E ET is required to provide credit support as defined in Calpine- The tolling agreement states that on the agreement. PG&E ET satisfied this obligation or before October 15, 2002, Calpine was to have by providing an investment-grade guarantee issued a full notice to proceed under its from PG&E NEG as defined in the tolling construction contract to its engineering, agreement. The amount of the guarantee as of procurement and construction contractor for the January 31, 2003 does not exceed $250 million.

Otay Mesa facility. On October 16, 2002, PG&E By letter dated August 31, 2002, Caledonia ET asked Calpine to confirm that it had issued advised PG&E ET that it believed an event of this full notice to proceed and Calpine was not default under the tolling agreement had taken able to do so to the satisfaction of PG&E ET. place with respect to this obligation as PG&E Consequently, PG&E ET advised Calpine by NEG was no longer investment-grade as defined letter dated October 30, 2002 that it was in the tolling agreement and because PG&E ET terminating the tolling agreement effective had failed to provide, within thirty days from the November 29, 2002. Calpine has indicated that downgrade substitute credit support that met the this termination was improper and constituted a requirement of the tolling agreement. Caledonia 162

has the right to terminate the agreement and counterparties in support of PG&E ET's energy seek a termination payment. In addition, PG&E trading and non-trading activities related to ET has provided Caledonia with a notice of PG&E NEG's merchant energy portfolio in the default respecting Caledonia's performance face amount of $2.7 billion. Typically, the overall under the agreement and concerning the exposure under these guarantees is only a inability of the facility to inject its output into the fraction of the face value of these guarantees, local grid. Caledonia has not cured this default since not all counterparty credit limits are fully and on February 4, 2003, PG&E ET provided a used at any time. As of December 31, 2002, notice of termination. PG&E NEG and its rated subsidiaries' aggregate exposure under these guarantees was On February 7, 2003, Southaven and Caledonia approximately $83 million. The amount of such filed emergency petitions to compel arbitration exposure varies daily depending on changes in or alternatively, a temporary restraining order market prices and net changes in position. In and preliminary injunction with the Circuit Court light of the downgrades, some counterparties for Montgomery County, Maryland. The Court have sought and others may seek replacement has denied the relief requested and set the security to collateralize the exposure guaranteed matter for hearing on February 27, 2003. by PG&E NEG and its various subsidiaries. PG&E GTN and PG&E ET have terminated the PG&E ET is not able to predict whether the arrangements pursuant to which PG&E GTN counterparties will seek to terminate the provided guarantees on behalf of PG&E ET such agreements or whether the Court will grant the that PG&E GTN will provide no new guarantees requested relief. Accordingly, it is not able to on behalf of PG&E ET.

predict whether or the extent to which, these proceedings will have a material adverse effect At December 31, 2002, PG&E ETs estimated on PG&E NEG's financial condition or results of exposure not covered by a guarantee (excluding operation. exposure under tolling agreements) is approximately $94 million.

Under each tolling agreement, determination of the termination payment is based on a formula To date, PG&E ET has met those replacement that takes into account a number of factors security requirements properly demanded by including market conditions such as the price of counterparties and has not defaulted under any power and the price of fuel. In the event of a of its master trading agreements although one dispute over the amount of any termination counterparty has alleged a default. No demands payment that the parties are unable to resolve by have been made upon the guarantors of PG&E negotiation, the tolling agreement provides for ETrs obligations under these trading agreements.

mandatory arbitration. The dispute resolution In the past, PG&E ET has been able to negotiate process could take as long as six months to acceptable arrangements and reduce its overall more than a year to complete. To the extent that exposure to counterparties when PG&E ET or its PG&E ET did not pay these damages, the counterparties have faced similar situations.

counterparties could seek payment under the There can be no assurance that PG&E ET can guarantees for an aggregate amount not to continue to negotiate acceptable arrangements in exceed $600 million. PG&E NEG is unable to the current circumstances. PG&E NEG cannot predict whether counterparties will seek to quantify with any certainty the actual future calls terminate their tolling agreements. PG&E NEG on PG&E Er's liquidity. PG&E NEG's and its does not currently expect to be able to pay any subsidiaries' ability to meet these calls on their termination payments that may become due. liquidity will vary with market price volatility, uncertainty with respect to PG&E NEG's financial Guarantees condition and the degree of liquidity in the energy markets. The actual calls for collateral PG&E NEG and certain subsidiaries have will depend largely upon counterparties' provided guarantees to approximately 232 responses to the ratings downgrades, 163

forbearance agreements, pre- and early-pay Harquahala and Covert projects pursuant to the arrangements, the continued performance of construction contracts. However, in the event PG&E NEG companies under the underlying that the construction contractor incurs certain agreements, whether counterparties have the unreimbursed project costs or cost overruns, the right to demand such collateral, the execution of contractor could assert a claim against PG&E master netting agreements and offsetting NEG's subsidiary or PG&E NEG under its transactions, changes in the amount of exposure, guarantees. PG&E NEG believes that the and the counterparties' other commercial construction contractor as of the date can validly considerations. assert no claim hereof.

Other Guarantees PG&E NEG has provided a $300 million guarantee to support a tolling agreement that a PG&E NEG has provided guarantees related to wholly owned subsidiary, Attala Energy other obligations by PG&E NEG companies to Company LLC, has entered into with another counterparties for goods or services. PG&E NEG wholly owned subsidiary, Attala Generating. See does not believe that it has significant exposure discussion in Note 7 under "Impairments, Write-under these guarantees. The most significant of offs, and Other Charges."

these guarantees relate to perfonnance under certain construction and equipment procurement The balance of the guarantees are for contracts. In the event PG&E NEG is unable to commitments undertaken by PG&E NEG or its provide any additional or replacement security subsidiaries in the ordinary course of business which may be required as a result of for services such as facility and equipment downgrades, the counterparty providing the leases, ash disposal rights, and surety bonds.

goods or services could suspend performance or terminate the underlying agreement and seek Contingencies recovery of damages. These guarantees represent guarantees of subsidiary obligations for PG&E Corporation transactions entered into in the ordinary course of business. Some of the guarantees relate to the PG&E Corporation has entered into contractual construction or development of PG&E NEG's obligations with healthcare providers to power plants and pipelines. These guarantees coordinate the payment of healthcare costs for are described below. PG&E Corporation and PG&E NEG. In the event that PG&E NEG is unable to fund future PG&E NEG has issued guarantees for the healthcare costs, PG&E Corporation could be in performance of the contractors building the the position of funding these costs. PG&-E NEG's Harquahala and Covert power projects for up to annual healthcare costs in 2002 were

$555 million. Any exposure under the guarantees approximately $21 million.

for construction completion is mitigated by guarantees in favor of PG&E NEG from the As further disclosed below, PG&E Corporation constructor and equipment vendors related to has guaranteed the Utility's reimbursement performance, schedule and cost. The constructor obligation associated with certain surety bonds and various equipment vendors are performing and the Utility's obligation to pay workers' under their underlying contracts. compensation claims.

PG&E NEG has issued $100 million of guarantees Uthity to the constructor of the Harquahala and Covert projects to cover certain separate cost-sharing Nuclear Insurance - The Utility has several arrangements. Failure to perform under those types of nuclear insurance for its Diablo Canyon separate cost-sharing arrangements or the related Power Plant, or DCPP, and Humboldt Bay Power guarantees would not have an impact on the Plant, or HBPP. The Utility has insurance constructor's obligations to complete the coverage for property damages and business 164

interruption losses as a member of Nuclear Workers' Compensation Security - The Utility Electric Insurance Limited, or NEIL. NEIL is a is self insured for workers' compensation. The mutual insurer owned by utilities with nuclear Utility must deposit collateral with the State facilities. Under this insurance, if a nuclear Department of Industrial Relations, or DIR, to generating facility insured by NEIL suffers severe maintain its status as a self-insurer for workers' losses and those losses exceed the resources of compensation claims made against the Utility.

NEIL, the Utility may be responsible for Acceptable forms of collateral include surety additional premiums of up to $32 million to bonds, letters of credit, cash, or securities. The cover property damages and business Utility currently provides collateral in the form of interruption for DCPP and up to $1.4 million to approximately $365 million in surety bonds.

cover property damages for HBPP.

In February 2001, several surety companies Under federal law, the Price-Anderson Act are provided cancellation notices because of the public liability claims from a nuclear incident Utility's financial situation. The DIR has not limited to $9.5 billion. As required by the Act, agreed to release the canceling sureties from the Utility has purchased the maximum available their obligations for claims occurring prior to the public liability insurance of $300 million for cancellation and has continued to apply the DCPP. The balance of the $9.5 billion of liability cancelled bond amounts, totaling $185 million, protection is covered by a loss-sharing program towards the $365 million amount of collateral.

(secondary financial protection) among utilities The Utility was able to supplement the difference owning nuclear reactors. Under the Act, through three additional active surety bonds secondary financial protection is required for all totaling $180 million. At December 31, 2002, the reactors of 100 MW or higher. If a nuclear cancelled bonds have not impacted the Utility's incident results in costs in excess of $300 million, self-insured status under California law. PG&E then the Utility may be responsible for up to Corporation has guaranteed the Utility's

$88 million per reactor with payments in each reimbursement obligation associated with these year limited to a maximum of $10 million per surety bonds and the Utility's underlying incident until the Utility has fully paid its share obligation to pay workers' compensation claims.

of the liability. Since the Utility has two nuclear reactors, of over 100 MW, the Utility may be Environmental Matters - The Utility may be assessed up to $176 million per incident with required to pay for environmental remediation at payments in year limited to a maximum of sites where it has been, or may be, a potentially

$20 million per incident. The Price-Anderson Act responsible party under the Comprehensive expired on August 1, 2002. By the terms of the Environmental Response Compensation and act itself, the provisions of the act will remain in Liability Act and similar state environmental laws.

effect until Congress renews the act. The current These sites include former manufactured gas draft of the bill to renew this act would increase plant sites, power plant sites, and sites used by the maximum assessment per nuclear incident the Utility for the storage, recycling, or disposal per unit to $99 million from $88 million, with of potentially hazardous materials. Under federal payments in each year limited to a maximum of and California laws, the Utility may be

$15 million per nuclear incident per unit, responsible for remediation of hazardous increased from $10 million. substances even if the Utility did not deposit those substances on the site.

Additionally, the Utility has purchased

$53.3 million of private liability insurance for The Utility records an environmental remediation HBPP and has a $500 million indemnification liability when site assessments indicate from the Nuclear Regulatory Commission for remediation is probable and a range of likely public liability arising from nuclear incidents clean-up costs can be reasonably estimated. The covering liabilities in excess of the $53.3 million Utility reviews its remediation liability on a of private liability insurance for HBPP. quarterly basis for each site that may be exposed to remediation responsibilities. The liability is an 165

estimate of costs for site investigations, waste remediation program and to expend remediation, operations and maintenance, (1) up to $22 million in hazardous substance monitoring, and site closure using (1) current remediation programs and procedures in each technology, (2) enacted laws and regulations, calendar year in which the Chapter 11 case is (3) experience gained at similar sites, and (4) the pending; and (2) any additional amounts in probable level of involvement and financial emergency situations involving post-petition condition of other potentially responsible parties. releases or threatened releases of hazardous Unless there is a better estimate within this range substances subject to the Bankruptcy Court's of possible costs, the Utility records the lower specific approval.

end of this range.

The California Attorney General, on behalf of The Utility had an undiscounted environmental various state environmental agencies, filed claims remediation liability of $331 million at in the Utility's bankruptcy proceeding for December 31, 2002, and $295 million at environmental remediation at numerous sites December 31, 2001. The $331 million accrued at totaling approximately $770 million. For most if December 31, 2002, includes (1) $138 million not all of these sites, the Utility is in the process related to the pre-closing remediation liability of remediation in cooperation with the relevant associated with divested generation facilities, and agencies and other parties responsible for (2) $193 million related to remediation costs for contributing to the clean-up in the normal course those generation facilities that the Utility still of business. Since the Utility's proposed plan of owns, manufactured gas plant sites, gas reorganization provides that the Utility intends to gathering sites, and compressor stations. Of the respond to these types of claims in the regular

$331 million environmental remediation liability, course of business, and since the Utility has not the Utility has recovered $188 million through argued that the bankruptcy proceeding relieves rates charged to its customers, and expects to the Utility of its obligations to respond to valid recover approximately $84 million of the balance environmental remediation orders, the Utility in future rates. The Utility also is recovering its believes the claims seeking specific cash costs from insurance carriers and from other recoveries are invalid.

third parties whenever it is possible.

PG&E NEG The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to PG&E NEG has substantial financial estimate. A change in the estimate may occur in contingencies in addition to the environmental the near term due to uncertainty concerning the matters discussed below. See Note 3 PG&E NEG Utility's responsibility, the complexity of Liquidity Matters for further discussion on PG&E environmental laws and regulations, and the NEG's financial contingencies.

selection of compliance alternatives. The Utility estimates the upper limit of the range using Environmental Matters assumptions least favorable to the Utility, which is based upon a range of reasonably possible In May 2000, USGenNE, an indirect subsidiary of outcomes. The Utility's future cost could increase PG&E NEG, received an Information Request to as much as $444 million if (1) the other from the U.S. Environmental Protection Agency potentially responsible parties are not financially (EPA), pursuant to Section 114 of the Federal able to contribute to these costs, (2) the extent Clean Air Act (CAA). The Information Request of contamination or necessary remediation is asked USGenNE to provide certain information greater than anticipated, or (3) the Utility is relative to the compliance of its Brayton Point found to be responsible for clean-up costs at and Salem Harbor plants with the CAA. No additional sites. enforcement action has been brought by the EPA to date. USGenNE has had preliminary On June 28, 2001, the Bankruptcy Court discussions with the EPA to explore a potential authorized the Utility to continue its hazardous settlement of this matter. Management believes 166

that it is not possible to predict, at this point, the new regulations. A local environmental whether any such settlement will occur or, in the group has made various filings with DEP absence of a settlement, the likelihood of requesting such participation.

whether the EPA will bring an enforcement action. The EPA is required under the CAA to establish new regulations for controlling hazardous air As a result of the EPA Information Request and pollutants from combustion turbines and environmental regulatory initiatives by the reciprocating internal combustion engines.

Commonwealth of Massachusetts, USGenNE is Although the EPA has yet to propose the exploring ways to achieve significant reductions regulations, the CAA required that they be of sulfur dioxide and nitrogen oxide emissions. promulgated by November 2000. Another Additional requirements for the control of provision in the CAA requires companies to mercury and carbon dioxide emissions also will submit case-by-case Maximum Achievable be forthcoming as part of these regulatory Control Technology (MACT) determinations for initiatives. Management believes that USGenNE individual plants if the EPA fails to finalize would meet these requirements through regulations within eighteen months past the installation of controls at the Brayton Point and deadline. On April 5, 2002, the EPA promulgated Salem Harbor plants and estimates that capital a regulation that extends this deadline for the expenditures on these environmental projects case-by-case permits until May 2004. The EPA could approximate $348 million over the next intends to finalize the MACT regulations before four years. To date, PG&E NEG has incurred this date, thus eliminating the need for the plant-expenditures related to these projects of specific permits. PG&E NEG will not be able to

$15.7 million. These estimates are currently accurately quantify the economic impact of the under review and it is possible that actual future regulations until more details are available expenditures may be higher. Based on an through the rulemaking process.

emission control plan filed for Brayton Point under the regulations implementing these PG&E NEG's existing power plants are subject to initiatives, the Massachusetts Department of federal and state water quality standards with Environmental Protection (DEP) ruled that respect to discharge constituents and thermal Brayton Point is required to meet the newer, effluents. Three of the fossil-fueled plants owned more stringent emission limitations for sulfur and operated by USGenNE (Salem Harbor, dioxide and nitrogen oxide by 2006. The DEP Manchester Street, and Brayton Point) are has ruled that Salem Harbor must satisfy these operating pursuant to National Pollutant limitations by 2004. Although it is USGenNE's Discharge Elimination System (NPDES) permits current intention to appeal DEP's ruling that that have expired. For the facilities whose Salem Harbor must comply with the new NPDES permits have expired, permit renewal regulations by 2004, in the absence of a applications are pending, and all three facilities successful appeal of the DEP's ruling, the are continuing to operate under existing terms compliance date for Salem Harbor remains and conditions until new permits are issued. On October 2004. USGenNE will not be able to July 22, 2002, the EPA and DEP issued a draft operate Salem Harbor unless it is in compliance NPDES permit for Brayton Point that, among with these emission limitations. PG&E NEG other things, substantially limits the discharge of believes that it is impossible to meet the heat by Brayton Point into Mount Hope Bay.

October 2004 deadline. Therefore, it may not be Based on its initial review of the draft permit, able to operate the facility after that deadline. USGenNE believes that the draft permit is excessively stringent. It is estimated that Various aspects of DEP's regulations allow for USGenNE's cost to comply with the new permit public participation in the process through which conditions could be as much as $248 million DEP determines whether the 2004 or 2006 through 2006, but this is a preliminary estimate.

deadline applies and approves the specific There are various administrative and judicial activities that USGenNE will undertake to meet proceedings that must be completed before the 167

draft NPDES permit for Brayton Point becomes nationwide that would be affected by this final and these proceedings are not expected to rulemaking. The proposed rule calls for a set of be completed during 2003. In addition, it is performance standards that vary with the type of possible that the new permits for Salem Harbor water body and that are intended to reduce and Manchester Street may also contain more impacts to aquatic organisms. The final stringent limitations than prior permits and that regulations are scheduled to be promulgated in the cost to comply with the new permit February 2004. The extent to which they may conditions could be greater than the current require additional capital investment will depend estimate of $4 million. In addition, the issuance on the timing of the NPDES permit proceedings of any final NPDES permits may be affected by for the affected facilities. It is possible that the the EPA's proposed regulations under regulations may allow greater flexibility in Section 316(b) of the Clean Water Act. achieving specified permit limits and thereby reduce the cost of compliance.

On March 27, 2002, the Rhode Island Attorney General notified USGenNE of their belief that During April 2000, an environmental group Brayton Point "is in violation of applicable served USGenNE and other PG&E NEG's statutory and regulatory provisions governing its subsidiaries with a notice of its intent to file a operations...", including "protections accorded by citizen's suit under the Resource Conservation common law" respecting discharges from the Recovery Act. In September 2000, PG&E NEG facility into Mount Hope Bay. He stated that he signed a series of agreements with DEP and the intends to seek judicial relief "to abate these environmental group to resolve these matters environmental law violations and to recover that require PG&E NEG to alter its existing damages..." within the next 30 days. The notice wastewater treatment facilities at its Brayton purportedly was provided pursuant to section 7A Point and Salem Harbor generating facilities.

of chapter 214 of Massachusetts General Laws.

PG&E NEG believes that Brayton Point is in full PG&E NEG began the activities during 2000, and compliance with all applicable permits, laws, and is expected to complete them in 2003. PG&E regulations. The complaint has not yet been filed NEG incurred expenditures related to these or served. In early May 2002, the Rhode Island agreements of $5.4 million in 2000, $2.6 million Attorney General stated that he did not plan to in 2001, and $4.7 million in 2002. In addition to file the action until the EPA issues a draft Clean the costs previously incurred, PG&E NEG Water Act NPDES permit for Brayton Point. The maintains a reserve in the amount of $6 million EPA issued this draft permit on July 22, 2002, relating to its estimate of the remaining and the Rhode Island Attorney General has since environmental expenditures to fulfill its stated he has no intention of pursuing this matter obligations under these agreements. PG&E NEG until he reviews USGenNE's response to the draft has deferred costs associated with capital permit which was submitted on October 4, 2002. expenditures and has set up a receivable for Management is unable to predict whether he will amounts it believes are probable of recovery pursue this matter and, if he does, the extent to from insurance proceeds.

which it will have a material adverse effect on PG&E NEG's financial condition or results of PG&E NEG believes that it may be required to operation. spend up to approximately $608 million, excluding insurance proceeds, through 2008 for On April 9, 2002, the EPA proposed regulations environmental compliance to continue operating under Section 316(b) of the Clean Water Act for these facilities. This amount may change, cooling water intake structures. The regulations however, and the timing of any necessary capital would affect existing power generation facilities expenditures could be accelerated in the event using over 50 million gallons per day, typically of a change in environmental regulations or the including some form of "once-through" cooling. commencement of any enforcement proceeding Brayton Point, Salem Harbor, and Manchester against PG&E NEG. PG&E NEG has not made Street are among an estimated 539 plants any commitments to spend these amounts. In the 168

event PG&E NEG does not spend required named as parties in a number of claims and amounts as of each facility's compliance deadline lawsuits. The most significant of these are to maintain environmental compliance, PG&E discussed below. The Utility's Chapter 11 NEG may not be able to continue to operate one bankruptcy filing on April 6, 2001, discussed in or all of these facilities. Note 2 of the Notes to the Consolidated Financial Statements, automatically stayed the litigation Global climate change is a significant described below against the Utility, except as environmental issue that is likely to require otherwise noted.

sustained global action and investment over many decades. PG&E Corporation has been Chromium Litigation engaged on the climate change issue for several years and is working with others on developing There are 15 civil suits pending against the appropriate public policy responses to this Utility in several California state courts. One of challenge. PG&E Corporation continuously these suits also names PG&E Corporation as a assesses the financial and operational defendant. One additional civil suit, Kearney v.

implications of this issue; however, the outcome Pacific Gas and Electric Company, was filed and timing of these initiatives are uncertain. against the Utility and PG&E Corporation after the Utility's bankruptcy filing and was dismissed There are six greenhouse gases. The Utility and without prejudice while the plaintiffs sought the PG&E NEG emit varying quantities of these right to file and pursue late claims in the greenhouse gases, including carbon dioxide and Bankruptcy Court. In the Kearney case, the methane, in the course of their operations. Bankruptcy Court ruled that the six adult Depending on the ultimate regulatory regime put plaintiffs could not file untimely bankruptcy into place for greenhouse gases, PG&E claims against the Utility. The court also ruled Corporation's operations, cash flows and that the 24 minor plaintiffs could file untimely financial condition could be adversely affected. bankruptcy claims against the Utility. The suits Given the uncertainty of the regulatory regime, it allege personal injuries, wrongful death, and loss is not possible to predict the extent to which of consortium and seek compensatory and climate change regulation will have a material punitive damages based on claims arising from adverse effect on the Utility's or PG&E NEG's alleged exposure to chromium in the vicinity of financial condition or result of operations. the Utility's gas compressor stations at Hinkley and Kettleman, California, and the area of PG&E NEG and the Utility are taking numerous California near Topock, Arizona. Currently, there steps to manage the potential risks associated are approximately 1,200 plaintiffs in the with the eventual regulation of greenhouse chromium litigation cases.

gases, including but not limited to preparing inventories of greenhouse gas emissions, The Utility is responding to the suits in which it voluntarily reporting on these emissions through has been served and is asserting affirmative a variety of state and federal programs, engaging defenses. The Utility will pursue appropriate in demand side management programs that legal defenses, including statute of limitations, prevent greenhouse gas emissions, and exclusivity of workers' compensation laws, and supporting market-based solutions to the climate factual defenses, including lack of exposure to change challenge. chromium and the inability of chromium to cause certain of the illnesses alleged.

Legal Matters In the normal course of business, PG&E Corporation, the Utility, and PG&E NEG are 169

In the case of Adams v. Pacific Gas and Electric Natural Gas Royalties Litigation Company and Betz Chemical Company, after a hearing on July 17, 2002, the state court This litigation involves the consolidation of dismissed 35 plaintiffs with prejudice because approximately 77 False Claims Act cases filed in their claims are barred by the statute of various federal district courts by Jack J. Grynberg limitations. The state court dismissed another 65 (called a relator in the parlance of the False plaintiffs without prejudice, so these plaintiffs Claims Act) on behalf of the United States of may attempt to prove that their claims are not America, against more than 330 defendants, barred by the statute of limitations. Thirty of including the Utility and PG&E GTN. The cases these plaintiffs filed a Fourth Amended were consolidated for pretrial purposes in the Complaint on October 16, 2002. The other 35 District of Wyoming. The current case grows out plaintiffs who were given leave to amend have of prior litigation brought by the same relator in been dismissed with prejudice for failure to 1995 that was dismissed in 1998.

amend.

Under procedures established by the False Approximately 1,260 individuals have filed Claims Act, the United States, acting through the proofs of claims with the Bankruptcy Court Department of Justice (DOJ), is given an (most are plaintiffs in the 15 cases) alleging that opportunity to investigate the allegations and to exposure to chromium in soil, air, or water at or intervene in the case and take over its near the Utility's compressor stations at Hinkley prosecution if it chooses to do so. In April 1999, and Kettleman, California, and the area of the U.S. DOJ declined to intervene in any of the California near Topock, Arizona, caused personal cases.

injuries, wrongful death, or related damages.

Approximately 1,035 of these claimants have The complaints allege that the various filed proofs of claim requesting an approximate defendants (most of which are pipeline aggregate amount of $580 million and companies or their affiliates) incorrectly approximately another 225 claimants have filed measured the volume and heat content of natural claims for an "unknown amount." On gas produced from federal or Indian leases. As a November 14, 2001, the Utility filed objections to result, it is alleged that the defendants these claims and requested the Bankruptcy Court underpaid, or caused others to underpay, the to transfer the chromium claims to the federal royalties that were due to the United States for District Court. On January 8, 2002, the the production of natural gas from those leases.

Bankruptcy Court denied the Utility's request to The complaints do not seek a specific dollar transfer the chromium claims and granted certain amount or quantify the royalties claim. The claimants' motion for relief from stay so that the complaints seek unspecified treble damages, civil state court lawsuits pending before the Utility penalties, and expenses associated with the filed its bankruptcy petition can proceed. Orders litigation.

granting relief from stay have been entered.

The relator has filed a claim in the Utility's The Utility has recorded a reserve in its financial bankruptcy case for $2.5 billion, $2 billion of statements in the amount of $160 million for which is based upon the plaintiffs calculation of these matters. PG&E Corporation and the Utility penalties sought against the Utility.

believe that, after taking into account the reserves recorded at December 31, 2002, the PG&E Corporation and the Utility believe the ultimate outcome of this matter will not have a allegations to be without merit and intend to material adverse impact on PG&E Corporation's present a vigorous defense. PG&E Corporation or the Utility's financial condition or future and the Utility believe that the ultimate outcome results of operations. of the litigation will not have a material adverse effect on their financial condition or results of operations.

170

FederalSecuritiesLawsuit complaint. After a hearing held on June 24, 2002, the District Court issued an order on June 25, On April 16, 2001, a complaint was filed against 2002, granting the defendants' motion to dismiss PG&E Corporation and the Utility in the U.S. the second amended complaint. The dismissal is District Court for the Central District of with prejudice, prohibiting the plaintiffs from California. The Utility was subsequently filing a further complaint. On November 15, dismissed, due to its Chapter 11 bankruptcy 2002, the plaintiffs filed an appeal in the United filing. By order entered on or about May 31, States Court of Appeals for the Ninth Circuit, 2001, the case was transferred to the U.S. District advancing substantially the same arguments that Court for the Northern District of California. On the District Court had rejected previously.

August 9, 2001, plaintiff filed a first amended Defendants filed their answer to the appeal on complaint in the U.S. District Court for the January 2, 2003.

Northern District of California. An executive officer of PG&E Corporation also has been PG&E Corporation believes the allegations to be named as a defendant. The first amended without merit and intends to present a vigorous complaint, purportedly brought on behalf of all defense. PG&E Corporation believes that the persons who purchased PG&E Corporation ultimate outcome of the litigation will not have a common stock or certain shares of the Utility's material adverse effect on its financial condition preferred stock between July 20, 2000, and or results of operations.

April 9, 2001, claimed that the defendants caused PG&E Corporation's Consolidated Financial OrderInstituting Investigation (OHI) into Statements for the second and third quarters of Holding Company Activities and Related 2000 to be materially misleading in violation of Litigation federal securities laws as a result of recording as a deferred cost and capitalizing as a regulatory On April 3, 2001, the CPUC issued an OIl into asset the under-collections that resulted when whether the California IOUs, including the escalating wholesale energy prices caused the Utility, have complied with past CPUC decisions, Utility to pay far more to purchase electricity rules, or orders authorizing their holding than it was permitted to collect from customers. company formations and/or governing affiliate On January 14, 2002, the District Court granted transactions, as well as applicable statutes. The the defendants' motion to dismiss the plaintiffs' order states that the CPUC will investigate (1) the first amended complaint, finding that the utilities' transfer of money to their holding complaint failed to state a claim in light of the companies since deregulation pf the electric public disclosures by PG&E Corporation, the industry commenced, including during times Utility, and others regarding the under- when their utility subsidiaries were experiencing collections, the risk that they might not be financial difficulties, (2) the failure of the holding recoverable, the financial consequences of companies to financially assist the utilities when non-recovery, and other information from which needed, (3) the transfer by the holding analysts and investors could assess for companies of assets to unregulated subsidiaries, themselves the probability of recovery. and (4) the holding companies' action to "ringfence" their unregulated subsidiaries. The On February 4, 2002, the plaintiffs filed a second CPUC also will determine whether additional amended complaint that, in addition to rules, conditions, or changes are needed to containing many of the same allegations as were adequately protect ratepayers and the public in the first amended complaint, contains many of from dangers of abuse stemming from the the same allegations that appear in the California holding company structure. The CPUC will Attorney General's complaint discussed below. investigate whether it should modify, change, or The plaintiffs sought an unspecified amount of add conditions to the holding company compensatory damages, plus costs and attorneys' decisions, make further changes to the holding fees. On March 11, 2002, the defendants filed a company structure, alter the standards under motion to dismiss the second amended which the CPUC determines whether to 171

authorize the formation of holding companies, its written decision adopted on January 9, 2002, otherwise modify the decisions, or recommend the CPUC stated that PG&E Corporation was statutory changes to the California Legislature. As being dismissed so that an appropriate legal a result of the investigation, the CPUC may forum could decide expeditiously whether impose remedies, prospective rules, or adoption of the Utility's proposed Plan of conditions, as appropriate. Reorganization would violate the first priority condition. The utilities' applications for rehearing On January 9, 2002, the CPUC issued an interim were denied on July 17, 2002.

decision and order interpreting the "first priority condition" adopted in the CPUC's holding The holding companies have filed petitions for company decision. This condition requires that review of both the CPUC's capital requirements the capital requirements of the Utility, as and jurisdiction decisions in several state determined to be necessary and prudent to meet appellate courts, and the utilities also have filed the Utility's obligation to serve or to operate the petitions for review of the capital requirements Utility in a prudent and efficient manner, be decision with the California appellate courts. The given first priority by the board of directors of CPUC moved to consolidate all proceedings in the holding company. In the interim order, the the San Francisco state appellate court and CPUC stated, "the first priority condition does requested that the court extend the deadline by not preclude the requirement that the holding which the CPUC must file its responses to the company infuse all types of capital into their petitions for review until after the consolidation respective utility subsidiaries where necessary to occurred. The CPUC's request for consolidation fulfill the Utility's obligation to serve." The three was granted and all of the petitions are now major California investor-owned energy utilities before the First Appellate District in San and their parent holding companies had Francisco, California.

opposed the broader interpretation, first contained in a proposed decision released for On January 10, 2002, the California Attorney comment on December 26, 2001, as being General filed a complaint in the San Francisco inconsistent with the prior 15 years' Superior Court against PG&E Corporation and its understanding of that condition as applying more directors, as well as against directors of the narrowly to a priority on capital needed for Utility, alleging that PG&E Corporation violated investment purposes. The CPUC also interpreted various conditions established by the CPUC in the first priority condition as prohibiting a decisions approving the holding company holding company from (1) acquiring assets of its formation, among other allegations. The Attorney utility subsidiary for inadequate consideration, General also alleged that the December 2000 and and (2) acquiring assets of its utility subsidiary at January and February 2001 ringfencing any price, if such acquisition would impair the transactions by which PG&E Corporation utility's ability to fulfill its obligation to serve or subsidiaries complied with credit rating agency to operate in a prudent and efficient manner. criteria to establish independent credit ratings The utilities' applications for rehearing were violated the holding company conditions.

denied on July 17, 2002.

Among other allegations, the Attorney General In a related decision, the CPUC denied the alleged that, through the Utility's bankruptcy motions filed by the California utility holding proceedings, PG&E Corporation and the Utility companies to dismiss the holding companies engaged in unlawful, unfair, and fraudulent from the pending investigation on the basis that business practices in alleged violation of the CPUC lacks jurisdiction over the holding California Business and Professions Code companies. However, in the interim decision Section 17200 by seeking to implement the interpreting the first priority condition discussed transactions contemplated in the proposed Plan above, the CPUC separately dismissed PG&E of Reorganization filed in the Utility's bankruptcy Corporation (but no other utility holding proceeding. The complaint also seeks restitution company) as a respondent to the proceeding. In of assets allegedly wrongfully transferred to 172

PG&E Corporation from the Utility. On Corporation filed a motion to dismiss the February 8, 2002, PG&E Corporation filed a complaint. Subsequently, the City filed a motion notice of removal in the Bankruptcy Court to to remand the action to state court. In June 2002, transfer the Attorney General's complaint to the the Bankruptcy Court issued an Amended Order Bankruptcy Court. On February 15, 2002, PG&E on Motion to Remand stating that the Bankruptcy Corporation filed a motion to dismiss the lawsuit, Court retained jurisdiction over the causes of or in the alternative, to stay the suit with the action for conversion and unjust enrichment, Bankruptcy Court. Subsequently, the Attorney finding that these claims belong solely to the General filed a motion to remand the action to Utility and cannot be asserted by the City and state court. In June 2002, the Bankruptcy Court County, but remanding the Section 17200 cause held that federal law preempted the Attorney of action to state court. Both parties have General's allegations concerning PG&E appealed the Bankruptcy Court's remand order.

Corporation's participation in the Utility's The appeal and cross-appeal are pending in the bankruptcy proceedings. The Bankruptcy Court U.S. District Court for the Northern District of directed the Attorney General to file an amended California.

complaint omitting these allegations and remanded the amended complaint to the San Following remand, PG&E Corporation brought a Francisco Superior Court. Both parties have motion to strike. This motion is pending. PG&E appealed the Bankruptcy Court's remand order. Corporation also moved to coordinate this case The appeal and cross-appeal are pending in the with the Section 17200 case brought by Cynthia U.S. District Court for the Northern District of Behr, which is discussed below. That motion was California. granted.

On August 9, 2002, the Attorney General filed its In addition, a third case, entitled Cynthia Behr v.

amended complaint in the San Francisco PG&E Corporation, et al., was filed on Superior Court, omitting the allegations February 14, 2002 by a private plaintiff (who also concerning PG&E Corporation's participation in has filed a claim in bankruptcy) in Santa Clara the Utility's bankruptcy proceedings. PG&E Superior Court also alleging a violation of Corporation and the directors named in the California Business and Professions Code complaint have filed a motion to strike certain Section 17200. The Behr complaint also names allegations of the amended complaint. Those the directors of PG&E Corporation and the Utility motions are pending. as defendants. The allegations of the complaint are similar to the allegations contained in the On February 11, 2002, a complaint entitled City Attorney General's complaint but also include and County of San Francisco;People of the State allegations of fraudulent transfer and violation of of Californiav. PG&E Corporation, and Does the California bulk sales laws. Plaintiff requests 1-150, was filed in San Francisco Superior Court. the same remedies as the Attorney General's The complaint contains some of the same case and in addition requests damages, allegations contained in the Attorney General's attachment, and restraints upon the transfer of complaint, including allegations of unfair defendants' property. On March 8, 2002, PG&E competition. In addition, the complaint alleges Corporation filed a notice of removal in the causes of action for conversion, claiming that Bankruptcy Court to transfer the complaint to the PG&E Corporation "took at least $5.2 billion Bankruptcy Court. Subsequently, the plaintiff from the Utility," and for unjust enrichment. The filed a motion to remand the action to state City seeks injunctive relief, the appointment of a court. In its June 2002 ruling mentioned above as receiver, payment to ratepayers, disgorgement, to the Attorney General's and the City's cases, the imposition of a constructive trust, civil the Bankruptcy Court retained jurisdiction over penalties, and costs of suit. Behr's fraudulent transfer claim and bulk sales claim, finding them to belong to the Utility's After removing the city's action to the estate. The Bankruptcy Court remanded Behr's Bankruptcy Court on February 8, 2002, PG&E Section 17200 claim to the Santa Clara Superior 173

Court. Both parties have appealed the an impermissible collateral action and on the Bankruptcy Court's remand order. The appeal basis that the alleged facts, even if assumed to and cross-appeal are pending in the U.S. District be true, do not establish that currently Court for the Northern District of California. authorized electric rates are not reasonable. On May 10, 2002, the Utility filed a motion to Following remand, PG&E Corporation moved to dismiss the complaint. The CPUC has not yet have the Behr case coordinated with the City's issued a decision. PG&E Corporation and the case described above. That motion was granted, Utility believe that the ultimate outcome of this and the Behr case will now proceed in San matter will not have a material adverse effect on Francisco Superior Court. their financial condition or results of operations.

PG&E Corporation and the Utility believe that Recorded Liability for Legal Matters they have complied with applicable statutes, CPUC decisions, rules, and orders. Neither the In accordance with SFAS No. 5, "Accounting for Utility nor PG&E Corporation, however, can Contingencies," PG&E Corporation makes a predict what the outcome of the CPUC's provision for a liability when it is both probable investigation will be or whether the outcome will that a liability has been incurred and the amount have a material adverse effect on their results of of the loss can be reasonably estimated. These operations or financial condition. PG&E provisions are reviewed quarterly and adjusted to Corporation believes that the allegations of the reflect the impacts of negotiations, settlements complaints are without merit and will vigorously and payments, rulings, advice of legal counsel, respond to and defend the litigation. PG&E and other information and events pertaining to a Corporation cannot predict whether the outcome particular case. In 2001, the Utility increased its of the litigation will have a material adverse provision for legal matters due to a significant effect on its results of operations or financial case that had a potential material financial condition.

impact on the Utility. In 2002, the Utility adjusted Wifliam Ahern, et aL v. Pacific Gas and its provision again due to the settlement of that Eectric Company case without any damages awarded to the other parties.

On February 27, 2002, a group of 25 ratepayers filed a complaint against the Utility at the CPUC The provision for legal matters is included in demanding an immediate reduction of PG&E Corporation's and the Utility's other approximately $0.035 kWh in allegedly excessive noncurrent liabilities in the Consolidated Balance electric rates and a refund of alleged recent Sheets. The following table reflects the current over-collections in electric revenue since June 1, year's activity to the recorded liability for legal 2001. The complaint claims that electric rate matters for the Utility:

surcharges adopted in the first quarter of 2001 due to the high cost of wholesale power (in mlons) 2002 2001 (surcharges that increased the average electric Beginning balance, January 1...... $....

209 $185 Provision for liabilities ...... ........ 27 7 rate by $0.04 per kWh) became excessive later in Payments .......... ............ (5) (2) 2001. (In January 2001, the CPUC authorized a Adjustments ........ ............ (29) 19

$0.01 per kWh increase to pay for energy Ending balance, December 31 ...... $....

202 S209 procurement costs. In March 2001, the CPUC authorized an additional $0.03 per kWh electric rate increase as of March 27, 2001, to pay for NOTE 17: SEGMENT INFORMATION energy procurement costs, which the Utility began to collect in June 2001.) The only alleged PG&E Corporation has identified three reportable over-collection amount calculated in the operating segments based on similarities in the complaint is approximately $400 million during following characteristics:

the last quarter of 2001. On April 2, 2002, the

• Economic characteristics; Utility filed an answer, arguing that the complaint should be denied and dismissed immediately as

• Products and services; 174

• Types of customers; marketing and trading of electricity, various fuels and other energy-related commodities

• Methods of distribution; throughout North America.

• Regulatory environment; and PG&E NEG's Interstate Pipeline

• How information is reported to and used operations - owns, operates and develops by PG&E Corporation's chief operating interstate natural gas transmission pipeline decision maker.

facilities which run from Canada/United States border to the California/Oregon border.

The Utility is one reportable operating segment and the other two are part of PG&E NEG. These In December 2002, the Board of PG&E three reportable operating segments provide Corporation approved the sale of USGenNE and products and services and are subject to different Mountain View. The sale transaction for forms of regulation or jurisdictions. PG&E Mountain View was closed on January 31, 2003.

Corporation's reportable segments are described Both entities have been accounted for as assets below:

held for sale at December 31, 2002, and the operating results are being reported as Utility - provides natural gas and electric service in Northern and Central California. discontinued operations.

During 2000, PG&E NEG disposed of PG&E ES PG&E NEG's Integrated Energy & Marketing and PG&E GIT through a sale.

Activities - engages in the generation, transport, 175

Segment information for the years 2002, 2001, and 2000, is as follows:

PG&E National Energy Group (')

Integrated PG&E PG&E Total Energy & Interstate NEG Corporation, PG&E Marketing Pipeline Elimi- Eliminations (In millions) Utility NEG Activities Operations nations and Other (2) Total 2002 Operating revenues (31................. $10,505 $ 1,990 S 1,817 $ 206 $ (33) $12,495 Intersegment revenues (4) ............... 9 85 38 47 (94)

Total operating revenues. 10,514 2,075 1,855 253 (33) (94) 12,495 Depreciation, amortization, and decommissioning 1,193 116 70 46 1,309 Interest income. 74 18 17 4 (3) 40 132 Interest expense. (988) (202) (136) (35) (31) (264) (1,454)

Income tax provision (benefit) ..... 1,178 (656) (1,186) 44 486 (565) (43)

Income (loss) from continuing operations. 1,794 (2,225) (1,722) 79 (582) 374 (57)

Net income (loss). 1,794 (3,423) (2,417) 79 (1,085) 755 (874)

Capital expenditures. 1,546 1,485 1,294 191 1 3,032 Total assets at year-end .6. 24,551 7,945 7,550 1.341 (946) 1,200 33,696 2001 (7)

Operating revenues t .t 10,450 1,760 1,560 206 (6) 12,210 Intersegment revenues (4 12 160 120 40 (172)

Total operating revenues. 10,462 1,920 1,680 246 (6) (172) 12,210 Depreciation, amortization, and decommissioning 896 101 54 42 5 5 1,002 Interest income. 123 40 25 7 8 4 167 Interest expense. (974) (134) (71) (37) (26) (101) (1,209)

Income tax provision (benefit) (.. 596 (16) (47) 34 (3) (45) 535 Income (loss) from continuing operations. 990 67 (5) 76 (4) (74) 983 Net income (loss). 990 183 111 76 (4) (74) 1,099 Capital expenditures. 1,343 1,426 1,324 102 4 2,773 Total assets at year-end (6X.............. 25,269 10,298 8,891 1,251 156 396 35,963 2000 (7)

Operating revenues (2J ................ 9,623 2,945 1.873 i,o66 6 12,568 Inrersegment revenues (4 14 182 136 46 (196)

Total operating revenues. 9,637 3,127 2,009 1,112 6 (196) 12,568 Depreciation, amortization, and decommissioning 3,511 79 38 41 5 3,595 Interest income. 186 28 26 (3) 5 214 Interest expense (8) .................. (619) (155) (64) (90) (1) (14) (788)

Income tax provision (benefit) 15 .......... (2,154) 55 22 37 (4) (4) (2.103)

Income (loss) from continuing operations. (3,508) 93 5 78 10 (8) (3,423)

Net income (loss). (3,508) 152 104 78 (30) (8) (3.364)

Capital expenditures (9) ................ 1,245 1,089 1,074 15 2,334 Total assets at year-end (6)(............ 21,988 13,967 12,419 1,204 344 397 36,152

"' Income from equity method investees for Integrated Energy & Marketing were $48 million in 2002, $79 million in 2001, and

$65 million in 2000.

(2) Includes PG&E Corporation, PG&E Ventures LLC, and elimination ennies.

(' Operating revenues and expenses reflect the adoption during 2002 of a new accounting policy implementing a change from gross to net method of reporting revenues and expenses on trading activities. Prior year amounts for trading activities have been reclassified to conform with the new net presentation.

(4) Intersegment revenues are recorded at market prices, but the Utility uses rate set by the CPUC and PG&E NEG's Interstate Pipeline Operations uses rate set by the FERC.

'51 Income tax expense for the Utility was computed on a stand-alone basis. The balance of the consolidated income tax provision was allocated among PG&E Corporation and PG&E NEG.

(6) PG&E Corporation assets exclude its investments in subsidiaries.

7 Prior periods amounts have been restated to reflect the reclassification of USGenNE, Mountain View, and ET Canada operating results to discontinued operations.

'6 PG&E Corporation allocated its interest expense to subsidiaries in 2000.

(9) "PG&E Corporation Eliminations and Other" column includes capital spending of zero million in 2000 and total assets of

$1 million at Dec-ember 31, 2000, for the discontinued operations of PG&E ES.

176

QUARTERLY CONSOLIDATED FINANCIAL DAIA (UNAUDITED)

Quarter ended (in minlions, except per share amounts)

December 31 Septembcr 30 June 30 March 31 2002 PG&E CORPORATION Operating revenues (0 ....................... $ 2,968 $ 3,654 $ 2,938 $ 2,935 Operating income (loss) (2X3' .................. (1,949) 998 782 1,301 Income (loss) from continuing operations (2)X3) ..... (1,417) 459 278 623 Net income (loss) (2) ....................... (2,189) 466 218 631 Earnings (Loss) per common share from continuing operations, basic ......................... (3.72) 1.23 0.76 1.71 Earnings (Loss) per common share from continuing operations, diluted ........................ (3.72) 1.17 0.75 1.69 Common stock price per share High ........... 14.18 17.75 23.75 23.66 Low .................................. 8.17 8.00 16.35 18.86 Operating revenues ......................... $ 2,398 $ 2,949 $ 2,714 $ 2,453 Operating income .......................... 547 1,059 1,059 1,248 Net income ............................... 227 527 469 596 Income available for common stock ............. 221 520 463 590 2001 PG&E CORPORATION Operating revenues 0) ....................... $ 3,017 $ 3,489 $ 2,752 $ 2,952 Operating income (loss) (2X(3) .................. 1,051 1,527 1,404 (1,391)

Income (Loss) from continuing operations (2X3) ...... 506 747 718 (988)

Net income (loss) (2) ....................... 529 771 750 (951)

Earnings (Loss) per common share from continuing operations, basic ......................... 1.39 2.06 1.98 (2.72)

Earnings (Loss) per common share from continuing operations, diluted ........................ 1.38 2.05 1.98 (2.72)

Common stock price per share High .................................. 20.10 17.45 12.54 20.94 Low .................................. 14.96 11.66 6.50 8.38 U'rEIly Operating revenues ......................... $ 2,654 $ 2,937 $ 2,309 $ 2,562 Operating income (loss) ...................... 1,134 1,428 1,336 (1,420)

Net income (loss) .......................... 563 744 702 (994)

Income (Loss) available for (allocated to) common stock .................................. 557 737 696 (1,000)

"' Operating revenues and operating expenses reflect the adoption during the third quarter of 2002 of a new accounting policy implementing a change from gross to net method of reporting revenues and expenses on trading activities. All prior period amounts for trading activities have been reclassified to conform to the new net presentation.

(D2 In December 2002, the Board of Directors of PG&E Corporation approved the sale of USGenNE, Mountain View, and ET Canada. These entities have been accounted for as assets held for sale at December 31, 2002. The operating results have been excluded from continuing operations and reported as discontinued operations for all periods presented. A loss on 177

disposal of USGenNE and ET Canada of $767 million, net of income taxes of $381 million, was recorded for the quarter ended December 31, 2002. The earnings (loss) from operations of USGenNF, Mountain View, and ET Canada for quarters ending March 31, June 30, September 30, and December 31, 2002, were $8 million, S1 million. $7 million and ($5) million, respectively. The earnings from operations for the same periods in 2001 were $37 million, $32 million, $24 million, and

$14 million, respectively.

(31 Amounts have been restated to reflect the reclassification of USGenNE, Mountain View, and Er Canada operating results to discontinued operations. Operating income and income from continuing operations previously reported for the first three quarters in 2002 were $1,306 million and $631 million, $774 million and $279 million, and $1,005 million and $466 million, respectively. Operating income (loss) and income (loss) from continuing operations previously reported for the quarters ended March 31, June 30, September 30, and December 31, 2001, were ($1,340) million and ($951) million, $1,447 million and $750 million, $1,552 million and $771 million, and $1,077 million and $520 million, respectively.

178

INDEPENDENT AUDITORS' REPORT To the Boards of Directors and Shareholders of PG&E Corporation and Pacific Gas and Electric Company We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries (the "Company") and of Pacific Gas and Electric Company (a Debtor-in-Possession) and subsidiaries (the "Utility") as of December 31, 2002 and 2001, and the related consolidated statements of operations, cash flows and common stockholders' equity of the Company and the related consolidated statements of operations, cash flows and stockholders' equity of the Utility for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the respective managements of the Company and of the Utility. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.

An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the respective consolidated financial position of the Company and of the Utility as of December 31, 2002 and 2001, and the respective results of their consolidated operations and cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 of the Notes to the Consolidated Financial Statements, during 2002, the Company adopted new accounting standards to account for goodwill and intangible assets, impairment of long-lived assets, discontinued operations, gains and losses on debt extinguishment and certain derivative contracts. Additionally, during 2002, the Company changed the method of reporting gains and losses associated with energy trading contracts from the gross method to the net method and retroactively reclassified the consolidated statements of operations for 2001 and 2000. During 2001, as discussed in Note 1 of the Notes to the Consolidated Financial Statements, the Company and the Utility adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," and the Company adopted certain interpretations issued by the Derivatives Implementation Group of the Financial Accounting Standards Board.

The accompanying consolidated financial statements have been prepared on a going concern basis of accounting. As discussed in Notes I and 2 of the Notes to the Consolidated Financial Statements, the Utility, a subsidiary of the Company, has incurred power purchase costs substantially in excess of amounts charged to customers in rates. On April 6, 2001, the Utility sought protection from its creditors by filing a voluntary petition under provisions of Chapter 11 of the U.S. Bankruptcy Code. Additionally, as discussed in Note 3 of the Notes to the Consolidated Financial Statements, PG&E National Energy Group, a subsidiary of the Company, has defaulted on various debt and financing obligations. These matters raise substantial doubt about the ability of the Company and of the Utility to continue as going concerns. Managements' plans in regard to these matters are also described in Notes 2 and 3 of the Notes to the Consolidated Financial Statements. The respective consolidated financial statements do not include any adjustments that might result from the outcome of these uncertainties.

DELOITTE & TOUCHE LLP San Francisco, California February 24, 2003 179

RESPONSIBiITlY FOR THE CONSOLEDATED FINANCIAL STATEMENTS PG&E Corporation and Pacific Gas and Electric Company (the Utility) management are responsible for the integrity of the accompanying consolidated financial statements. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America.

Management considers materiality and uses its best judgment to ensure that such statements reflect fairly the financial position, results of operations, and cash flows of PG&E Corporation and the Utility.

PG&E Corporation and the Utility maintain systems of internal controls supported by formal policies and procedures, which are communicated throughout PG&E Corporation and the Utility. These controls are adequate to provide reasonable assurance that assets are safeguarded from material loss or unauthorized use and that necessary records are produced for the preparation of consolidated financial statements. There are limits inherent in all systems of internal controls, based on recognition that the costs of such systems should not exceed the benefits to be derived. PG&E Corporation and the Utility believe that their systems of internal control provide this appropriate balance. PG&E Corporation management also maintains a staff of internal auditors who evaluate the adequacy of, and assess the adherence to, these controls, policies, and procedures for all of PG&E Corporation, including the Utility.

Both PG&E Corporation's and the Utility's consolidated financial statements included herein have been audited by Deloitte & Touche LLP, PG&E Corporation's independent auditors. The audit includes consideration of internal accounting controls and performance of tests necessary to support an opinion.

The auditors' report contains an independent informed judgment as to the fairness, in all material respects, of reported results of operations and financial position.

The Audit Committee of the Board of Directors of PG&E Corporation meets regularly with management, internal auditors, and Deloitte & Touche LLP, jointly and separately, to review internal accounting controls and auditing and financial reporting matters. The internal auditors and Deloitte & Touche LLP have free access to the Audit Committee, which consists of five outside directors. The Audit Committee has reviewed the financial data contained in this report.

PG&E Corporation and the Utility are committed to full compliance with all laws and regulations and to conducting business in accordance with high standards of ethical conduct. Management has taken the steps necessary to ensure that all employees and other agents understand and support this commitment.

Guidance for corporate compliance and ethics is provided by an officers' Ethics Committee and by a Legal Compliance and Business Ethics organization. PG&E Corporation and the Utility believe that these efforts provide reasonable assurance that each of their operations is conducted in conformity with applicable laws and with their commitment to ethical conduct.

180

Boards of Directors of PG&E Corporation and Pacific Gas and Electric Companyl)

David R. Andrews Senior Vice President Government Affairs, General Counsel, and Secretary, PepsiCo, Inc.

David A. Coulter Vice Chairman, J.P. Morgan Chase & Co.

C. Lee Cox Vice Chairman, Retired, AirTouch Communications, Inc. and President and Chief Executive Officer, Retired, AirTouch Cellular Wiliam S. Davila President Emeritus, The Vons Companies, Inc. (retail grocery)

Robert D. Glynn, Jr.

Chairman of the Board, Chief Executive Officer. and President, PG&E Corporation and Chairman of the Board, Pacific Gas and Electric Company David M. Lawrence, MD Chairman and Chief Executive Officer, Retired, Kaiser Foundation Health Plan, Inc. and Kaiser Foundation Hospitals 181

Mary S. Metz President, S. H. Cowell Foundation Carl E. Reichardt Vice Chairman, Ford Motor Company, and Chairman of the Board and Chief Executive Officer, Retired, Wells Fargo & Company and Wells Fargo Bank, N.A.

Gordon R. Smith(')

President and Chief Executive Officer, Pacific Gas and Electric Company Barry Lawson Williams President, Williams Pacific Ventures, Inc. (business investment and consulting) 1b composition of the Boards of Directors is the same, except that Gordon R. Smith is a director The of the Pacific Gas and Electric Company Board of Directors only.

Advisory Director of PG&E Corporation and Pacific Gas and Electric Company Leslie S. Biller Vice Chairman and Chief Operating Officer, Retired, Wells Fargo & Company 182

Permanent Committees of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company(')

Executive Committees Subject to certain limits, may exercise the powers and perform the duties of the Boards of Directors.

Robert D. Glynn, Jr., Chair C. Lee Cox Mary S. Metz Carl E. Reichardt Gordon R. Smith")

Barry Lawson Williams Audit Committees Review financial and accounting practices, internal controls, external and internal auditing programs, business ethics, and compliance with laws, regulations, and policies that may have a material impact on the Consolidated Financial Statements. Satisfy themselves as to the independence and competence of the independent public accountants, select and appoint the firm of independent public accountants to audit PG&E Corporation's and Pacific Gas and Electric Company's accounts, and pre-approve all auditing and non-audit services provided by tile independent public accountants.

C. Lee Cox, Chair David R. Andrews William S. Davila Mary S. Metz Barry Lawson Williams Finance Committee Reviews financial and capital investment policies and objectives and specific actions required to achieve those objectives, long-term financial and investment plans and strategies, annual financial plans, dividend policy, short-term and long-term financing plans, proposed capital expenditures, proposed divestitures, major commercial and investment banking, financial consulting, and other financial relations, and risk management activities. Annually reviews a five-year financial plan that incorporates PG&E Corporation's business strategy goals, as well as an annual budget that reflects elements of the approved five-year plan.

Barry Lawson Williams, Chair David R. Andrews David A. Coulter Carl E. Reichardt 183

Nominating, Compensation, and Governance Committee Recommends candidates for nomination as directors and reviews the composition, performance, and compensation of the Boards of Directors. Reviews corporate governance matters, including the Corporate Governance Guidelines of PG&E Corporation and Pacific Gas and Electric Company.

Reviews employment, compensation, and benefits policies and practices, and long-range planning for executive development and succession.

Carl E. Reichardt, Chair David A. Coulter C. Lee Cox David M. Lawrence, MD Public Policy Committee Reviews public policy issues that could significantly affect the interests of customers, shareholders, or employees, policies and practices with respect to those issues, and significant societal, governmental, and environmental trends and issues that may affect the operations of PG&E Corporation, Pacific Gas and Electric Company, or their respective subsidiaries.

Mary S. Metz, Chair William S. Davila David M. Lawrence, MD Except for the Executive and Audit Committees, all committees listed above are committees of the PG&E Corporation Board of Directors. The Executive and Audit Committees of the PG&E Corporation and Pacific Gas and Electric Company Boards have the same members, except that Gordon R. Smith is a member of the Pacific Gas and Electric Company Executive Committee only.

184

PG&E Corporation Officers Robert D. Glynn, Jr.

Chairman of the Board, Chief Executive Officer, and President Peter A. Darbee Senior Vice President and Chief Financial Officer P. Chrisman Iribe Senior Vice President Christopher P. Johns Senior Vice President and Controller Thomas B. King Senior Vice President L E. Maddox Senior Vice President Daniel D. Richard, Jr.

Senior Vice President, Public Affairs Gordon R. Smith Senior Vice President G. Brent Stanley Senior Vice President, Human Resources Bruce R. Worthington Senior Vice President and General Counsel Leroy T. Barnes, Jr.

Vice President and Treasurer Leslie H. Everett Vice President and Assistant to the Chairman David S. Gee Vice President, Strategic Planning DeAnn Hapner Vice President, Special Projects Steven L Kline Vice President, Federal Governmental and Regulatory Relations Greg S. Pruett Vice President, Corporate Communications Gabriel B. Togneri Vice President, Investor Relations 185

PG&E National Energy Group Officers Thomas B. King President P. Chrisman Iribe Executive Vice President L E. Maddox Executive Vice President Pacific Gas and Electric Company Officers Robert D. Glynn, Jr.

Chairman of the Board Gordon R. Smith President and Chief Executive Officer Kent M. Harvey Senior Vice President, Chief Financial Officer, and Treasurer Roger J. Peters Senior Vice President and General Counsel James K. Randolph Senior Vice President and Chief of Utility Operations Daniel D. Richard, Jr.

Senior Vice President, Public Affairs Gregory M. Rueger Senior Vice President, Generation and Chief Nuclear Officer 186

Shareholder Information For financial and other information about PG&E Corporation and Pacific Gas and Electric Company, please visit our websites, www.pgecorp.com and www.pge.com, respectively.

If you have questions about your PG&E Corporation common stock account or Pacific Gas and Electric Company preferred stock account, please write or call Mellon Investor Services:

Mellon Investor Services P.O. Box 3310 (Securities Transfer)

P.O. Box 3315 (General Correspondence)

P.O. Box 3316 (Change of Address)

P.O. Box 3317 (Lost Certificate Replacement)

P.O. Box 3338 (Dividend Reinvestment)

South Hackensack, NJ 07606 Toll-free Telephone Services: 1.800.719.9056 Website: www.melloninvestor.com If you have general questions about PG&E Corporation or Pacific Gas and Electric Company, please write or call the Corporate Secretary's Office:

Corporate Secretary Linda Y.H. Cheng PG&E Corporation One Market, Spear Tower Suite 2400 San Francisco, CA 94105-1126 415.267.7070 Fax 415.267.7268 Securities analysts, portfolio managers, or other representatives of the investment community should write or call the Investor Relations Office:

Vice President, Investor Relations Gabriel B. Togneri PG&E Corporation One Market, Spear Tower Suite 2400 San Francisco, CA 94105-1126 415.267.7080 Fax 415.267.7265 PG&E Corporation General Information 415.267.7000 Pacific Gas and Electric Company General Information 415.973.7000 187

Stock Exchange Listings PG&E Corporation's common stock is traded on the New York, Pacific, and Swiss stock exchanges. The official New York Stock Exchange symbol is "PCG" but PG&E Corporation common stock is listed in daily newspapers under "PG&E" or "PG&E Cp."(1)

Pacific Gas and Electric Company has 11 issues of preferred stock, all of which are listed on the American and Pacific stock exchanges.

Newspaper Issue SymboI(')

First Preferred, Cumulative, Par Value $25 Per Share Redeemable:

7.04% . ............................................... PacGE pfU 6.57%o................................................. PacGE pfY 6.30%yo ............. I ................................. PacGE pfZ 5.00% . ............................................... PacGE pfD 5.00% Series A ........... .............................. PacGE pfE 4.80%0./ ............................................... PacGE pfG 4.50%0./ ............................................... PacGE pfH 4.36% .............. I ............................. PacGE pfl Non-Redeemable:

6.00% . ............................................... PacGE pfA 5.50%0./ ............................................... PacGE pfB 5.00%/6

o. .............................................. PacGE pfC The 7.90% Cumulative Quarterly Income Preferred Securities (QUIPS) were converted on May 24, 2002, to 7.90% Deferrable Interest Subordinated Debentures (QUIDS). For additional information on QUIDS, please refer to Note 4 of the "Notes to the Consolidated Financial Statements" section of this report.

Stock Held in Brokerage Accounts ("Street Name")

When you purchase your stock and it is held for you by your broker, the shares are listed with Mellon Investor Services in the broker's name, or "street name." Mellon Investor Services does not know the identity of the individual shareholders who hold their shares in this manner. They simply know that a broker holds a number of shares which may be held for any number of investors. If you hold your stock in a street name account, you receive all tax forms, publications, and proxy materials through your broker. If you are receiving unwanted duplicate mailings, you should contact your broker to eliminate the duplications.

Lost or Stolen Stock Certificates If you hold stock in your own name and your stock certificate has been lost, stolen, or in some way destroyed, you should notify Mellon Investor Services immediately.

') Local newspaper symbols may vary.

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PG&E Corporation Pacific Gas and Electric Company Annual Meetings of Shareholders Date: April 16, 2003 Time: 10:00 a.m.

Location: Masonic Auditorium, 1111 California Street San Francisco, California A joint notice of the annual meetings, joint proxy statement, and proxy card are being mailed with this annual report on or about March 21, 2003, to all shareholders of record as of February 18, 2003.

10-K Report If you would like a copy of the 2002 Form 10-K Report to the Securities and Exchange Commission, please contact the Office of the Corporate Secretary, or visit our websites, www.pgecorp.com and www.pge.com.

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