MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

PG&E Corporation, incorporated in California in 1995, is an energy-based holding company that conducts its business principally through Pacific Gas and Electric Company, or the Utility, a public utility operating in northern and central California. The Utility engages primarily in the businesses of electricity and natural gas distribution, electricity generation, procurement and transmission, and natural gas procurement, transportation and storage. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. Both PG&E Corporation and the Utility are headquartered in San Francisco, California. Through October 29, 2004, PG&E Corporation also owned National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., which engaged in electricity generation and natural gas transportation in the United States, or U.S., and which is accounted for as discontinued operations.

This is a combined annual report of PG&E Corporation and the Utility and includes separate Consolidated Financial Statements for each of these two entities. PG&E Corporation's Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility and other wholly owned and controlled subsidiaries. The Utility's Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. This combined Management's Discussion and Analysis of Financial Condition and Results of Operations, or MD&A, should be read in conjunction with the Consolidated Financial Statements and Notes to the Consolidated Financial Statements included in this annual report.

The Utility served approximately 4.9 million electricity distribution customers and approximately 4.1 million natural gas distribution customers at December 31, 2004. The Utility had approximately $34.3 billion in assets at December 31, 2004 and generated revenues of approximately $11.1 billion in 2004. Its revenues are generated mainly through the sale and delivery of electricity and natural gas.

The Utility is regulated primarily by the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC. The CPUC has jurisdiction to set the rates, terms and conditions of service for the Utility's electricity distribution, natural gas distribution and natural gas transportation and storage services in California, among other matters. The CPUC is also responsible for setting service levels and certain operating practices and for reviewing the Utility's capital and operating costs. In certain cases, the CPUC prescribes specific accounting treatment for capital and operating costs. The FERC has jurisdiction to set the rates, terms and conditions of service for the Utility's electricity transmission operations and wholesale electricity sales.

CPUC and FERC decisions have a significant impact on the amount of operating and capital costs the Utility incurs and the amount the Utility is authorized to recover from customers for these costs through the authorization of "revenue requirements." Revenue requirements are designed to allow the Utility an opportunity to recover its reasonable costs of providing utility services, including a return of, and a fair rate of return on, its investment in utility facilities, or rate base.

During 2004, several events had a significant impact on PG&E Corporation's and the Utility's results of operation and financial condition, including:

The Utility's plan of reorganization under Chapter 11 became effective on April 12, 2004, or the Effective Date. The plan of reorganization incorporated the terms of the settlement agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's Chapter 11 proceeding, or the Settlement Agreement. At March 31, 2004, the Utility recorded approximately $4.9 billion of regulatory assets established under the Settlement Agreement (including a $2.2 billion, after-tax, regulatory asset ($3.7 billion, pre-tax) referred to in this annual report as the Settlement Regulatory Asset) and a related pre-tax gain of approximately $4.9 billion on recognition of these regulatory assets. The Settlement Agreement authorizes the Utility to earn an 11.22% rate of return on equity on its rate base, including these regulatory assets. As described below, because the Utility refinanced the remaining unamortized after-tax balance of the Settlement Regulatory Asset through the issuance of approximately $1.9 billion of energy recovery bonds, the Utility will no longer earn this 11.22% rate of return on the Settlement Regulatory Asset as it is no longer a part of rate base.

The Settlement Agreement has a term of nine years that began on the Effective Date. Although the Utility's operations are no longer subject to the oversight of the bankruptcy court, the bankruptcy court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of (1) the Settlement Agreement, (2) the plan of reorganization, and (3) the bankruptcy court's December 22, 2003 order confirming the plan of reorganization. In addition, the bankruptcy court retains jurisdiction to resolve remaining disputed claims held in escrow of approximately $1.7 billion at December 31, 2004. See Note 2 of the Notes to the Consolidated Financial Statements for further discussion.

In March 2004, in anticipation of its emergence from Chapter 11, the Utility issued $6.7 billion in first mortgage bonds, or First Mortgage Bonds, and, together with its consolidated subsidiaries, obtained $2.9 billion in credit facilities, in order to finance the plan of reorganization. Upon the Effective Date, the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon resolution, and reinstated certain obligations. The Utility expects to fund its operating and capital expenditures substantially from internally generated funds. In addition, available credit facilities are considered adequate to meet these operating requirements and seasonal fluctuation in working capital.

Federal and state court appeals of the bankruptcy court's December 22, 2003 order confirming the plan of reorganization and the CPUC's approval of the Settlement Agreement remain pending. PG&E Corporation and the Utility believe these appeals and petitions are without merit. Under applicable federal precedent, once the plan of reorganization has been "substantially consummated," any pending appeals of the confirmation order should be dismissed. If, notwithstanding this federal precedent, the bankruptcy court's confirmation order or the Settlement Agreement is subsequently overturned or modified, PG&E Corporation and the Utility's financial condition and results of operations could be materially adversely affected. See Note 2 of the Notes to the Consolidated Financial Statements for further discussion.

Beginning January 1, 1998, electricity rates were frozen as required by the California electric industry restructuring law. In 2001, in response to the California energy crisis, the CPUC increased frozen rates by imposing fixed surcharges. As a result of the Settlement Agreement and various CPUC decisions, the Utility's electricity rates as of January 1, 2004, are no longer frozen and are determined based on its costs of service, including periodic adjustments to rates to reflect changes in sales or demand compared to forecast sales or demand. The Utility's electricity and natural gas distribution rates in 2004 reflected the sum of individual revenue requirement components including:

Changes in any individual revenue requirement will affect customers' electricity rates and the Utility's revenues. As a result, the Utility's net income is more predictable under cost-of-service ratemaking than under the previous rate freeze.

In December 2004, the CPUC approved the Utility's first annual electricity rate true-up to adjust rates to reflect over- and under-collections in the Utility's major electricity balancing accounts (including electricity procurement), and consolidate various other 2005 electricity revenue requirement changes authorized by the CPUC and the FERC. These rate changes, implemented on January 1, 2005, contemplated an increase in electricity revenues of approximately $274 million as compared to 2004 revenues at previously adopted rates. On February 7, 2005, the Utility requested the CPUC to approve a rate decrease, to be effective on March 1, 2005 of approximately $73 million, as compared to January 1, 2005 rates, to reflect the issuance of energy recovery bonds discussed below.

On May 27, 2004, the CPUC issued a decision in the Utility's 2003 GRC that determined the amount the Utility can collect from customers, or base revenue requirements, to recover its basic business and operational costs for electricity and natural gas distribution operations and for electricity generation operations for 2003 through 2006. The CPUC authorized base revenue requirements of approximately $4.3 billion for 2003, an increase of approximately $326 million over the previously authorized amounts. The amount of base revenue requirements authorized for 2004, 2005 and 2006, is based on the 2003 authorized amount, as increased each year to reflect the annual changes in the Consumer Price Index, or CPI, subject to certain minimum and maximum adjustments. These adjustments are called "attrition adjustments." Base revenue requirements in 2004, including attrition

adjustments totaled approximately $4.4 billion. See "Regulatory Matters" below for further detail of the terms of the 2003 GRC.

The impact of the approval of the GRC on the Utility's results of operations and financial condition is discussed below under "Results of Operations" and "Regulatory Matters."

On October 29, 2004, NEGT's plan of reorganization became effective, at which time NEGT emerged from Chapter 11 and PG&E Corporation's equity ownership in NEGT was cancelled. As a result, during the fourth quarter of 2004 PG&E Corporation recognized a one-time non-cash gain on the disposal of NEGT of approximately $684 million, as discussed below in the "Results of Operations" section.

In addition to future CPUC and FERC decisions that will affect the rates that the Utility can charge for its services and that will determine the amount of costs the Utility can recover through rates, the following significant factors are expected to affect the Utility's future results of operations and financial condition:

In connection with the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the remaining unamortized balance of the Settlement Regulatory Asset and related federal income and state franchise taxes, in an aggregate principal amount of up to $3.0 billion in two separate series up to one year apart, to be secured by a dedicated rate component, or DRC, to be collected from electricity customers as a nonbypassable charge. On February 10, 2005, PG&E Energy Recovery Funding LLC, or PERF, a limited liability company which is wholly owned and consolidated by the Utility (but legally separate from the Utility), issued approximately $1.9 billion of energy recovery bonds, or ERBs. The Utility, as servicer, will collect and remit DRC charges to PERF to enable PERF to pay the principal and interest on the ERBs. The proceeds of the ERBs were paid by PERF to the Utility and will be used by the Utility to refinance the remaining unamortized after-tax balance of the Settlement Regulatory Asset through the redemption and repurchase of higher cost equity and debt.

As a result of the issuance of the first series of ERBs, the Utility's 2005 net income will be reduced by approximately $100 million as compared to 2004 due to the elimination of the 11.22% return on common equity that the Utility earned on the Settlement Regulatory Asset and charged to customers during 2004.

In January 2005, the equity component of the Utility's capital structure reached 52%, the target specified in the Settlement Agreement. The Utility anticipates that it will use surplus cash to pay

dividends to, or repurchase common stock from, PG&E Corporation. As discussed below, under "Liquidity," the Boards of Directors of the Utility and PG&E Corporation each have declared a common stock dividend and have authorized substantial share repurchases.

The proceeds of the second series of ERBs, anticipated to be issued in November 2005 in an aggregate amount of up to $1.1 billion will be paid by PERF to the Utility to pre-fund the Utility's recovery through rates of the tax payments that will be due as the Utility collects the DRC over the term of the first series of ERBs to pay principal. The Utility anticipates that it will use the proceeds from the second series of ERBs to repay outstanding debt, or repurchase common stock from, PG&E Corporation or make additional needed investments in the Utility's rate base. Until taxes are fully paid, the Utility will compensate customers, computed at the Utility's authorized rate of return on rate base, for the use of the proceeds. This credit, along with energy supplier refunds received after the second series of ERBs is issued, other credits and costs related to the ERBs, will be reflected in rates. It is estimated that providing this "carrying cost credit" to customers could result in a decrease of up to $60 million in the Utility's 2006 net income. The actual impact on 2006 net income will depend on the principal amount of the second series of ERBs issued, which, in turn, depends on the timing and amount of refunds the Utility receives from energy suppliers through the related FERC proceedings. The carrying cost credit and the resulting impact on net income will decline as the taxes are paid, reaching zero in 2012 when the ERBs and related taxes are paid in full. See Note 2 of the Notes to the Consolidated Financial Statements for further discussion.

As a regulated utility, the Utility is obligated to procure electricity to meet the needs of its customers. The amount of electricity needed to meet the demands of customers, plus applicable reserve margins, that is not satisfied from the Utility's own generation facilities, the Utility's electricity purchase contracts, or from the DWR's electricity purchase contracts allocated to the Utility's customers, is referred to as the Utility's residual net open position. Electricity procurement costs significantly impacted the Utility's results of operations and financial condition during the California energy crisis. California legislation has been enacted which allows the Utility to recover its reasonably incurred wholesale electricity procurement costs and includes a mandatory rate adjustment provision that requires the CPUC to adjust rates on a timely basis to ensure that the Utility recovers its costs. Accordingly, during 2004, electricity procurement costs did not have the same impact on the Utility's results of operations that they had during the California energy crisis. The level of electricity procurement costs and revenues continue to have an impact on cash flows.

In December 2004, the CPUC issued a final decision which approved, with certain modifications, each California investor-owned electric utility's long-term electricity procurement plan, or LTPP, in order to authorize each utility to plan for and procure the resources necessary to provide reliable service to their customers for the ten-year period, 2005-2014. The utilities are required to solicit bids from providers of all potential sources of new generation (e.g., conventional or renewable resources to be provided under utility owned turnkey developments, or under third party power purchase agreements) through a single, open, transparent and competitive request for offers, or RFO, process, although a utility can tailor a RFO to meet specific resource needs.

The decision notes that there is a great degree of uncertainty as to the amount of load the existing utilities will be responsible for serving in the future. Among other provisions, the decision:

Operating expenses are a key factor in determining whether the Utility earns the rate of return authorized by the CPUC. Many of the Utility's costs, including electricity procurement costs, discussed above, are subject to ratemaking mechanisms that are intended to provide the Utility the opportunity to fully recover these costs. In the Utility's GRC, the CPUC authorizes the Utility to collect a fixed revenue requirement from customers that is intended to enable the Utility to recover its operating and maintenance expenses. If the Utility's operating expenses exceed the amount of the authorized revenue requirement, the Utility's results of operations and ability to earn its authorized rate of return may be affected.

Distribution, Generation, Transmission And Natural Gas Transportation Operating Assets

The Utility's distribution, generation, transmission and natural gas transportation operating assets generally consist of long-lived assets with significant construction and maintenance costs. A significant outage at any of these facilities may have a material impact on the Utility's operations. Costs associated with replacement electricity and natural gas or use of alternative facilities during these outages could have an adverse impact on PG&E Corporation's and the Utility's results of operations and liquidity.

The Utility's annual capital expenditures are expected to average approximately $2.0 billion annually over the next five years from 2005 through 2009 and are estimated to result in rate base growth of approximately 4.5%. As discussed below under "Capital Expenditures," the Utility could make additional capital expenditures that would further increase rate base growth to 6.5% from 2005 through 2009.

Strategy to Achieve Cost Efficiencies and Operational Excellence and to Invest in Needed Utility Infrastructure

With its exit from Chapter 11 and the return to cost-of-service ratemaking for electric distribution and generation operations, the Utility aims to earn no less than its authorized rate of return, generate strong cash flow, ensure adequate liquidity, and strengthen its credit rating. To achieve these goals, the Utility's strategy is to:

It is expected that the Utility would use cash in excess of amounts needed for operations, debt service and base capital expenditures, to pay regular quarterly dividends, to make incremental capital expenditures needed to serve its customers, and to repurchase its common stock. In turn, it is expected that PG&E Corporation would use the cash received from the Utility in the form of dividends or share repurchases to pay regular dividends to, or repurchase common stock from, its shareholders.

This combined Annual Report and the letter to shareholders that accompanies it contain forward-looking statements that are necessarily subject to various risks and uncertainties the realization or resolution of which are outside of management's control. These statements are based on current expectations and projections about future events, and assumptions regarding these events and management's knowledge of facts at the time the statements were made. These forward-looking statements are identified by words such as "assume," "expect," "intend," "plan," "project," "believe," "estimate," "predict," "anticipate," "may," "might," "will," "should," "would," "could," "goal," "potential" and similar expressions. Although PG&E Corporation and the Utility are not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include:

See the section below entitled "Risk Factors" for a further discussion of the more significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation's and the Utility's future results of operations and financial condition.

The table below details certain items from the accompanying Consolidated Statements of Operations for 2004, 2003 and 2002.

As discussed above under "Overview," as of January 1, 2004, the Utility no longer collects frozen electricity rates. Instead, the Utility's electric rates are designed to fully recover the Utility's costs of service, including wholesale electricity procurement costs.

California legislation has been enacted which allows the Utility to recover its reasonably incurred wholesale electricity procurement costs and includes a mandatory rate adjustment provision which requires the CPUC to adjust rates on a timely basis to ensure that the Utility recovers its costs. Accordingly, with the implementation of new CPUC-approved electricity balancing accounts and cost of service ratemaking in 2004, electricity procurement costs and items such as changes in sales volumes have not had the same impact on the Utility's results of operations that they had during the California energy crisis when rates were frozen. The level of the Utility's electricity procurement costs continue to have an impact on cash flows.

Due to the recognition of the Settlement Regulatory Asset and generation-related regulatory assets provided under the Settlement Agreement, net income for 2004 reflects a one-time non-cash gain of approximately $2.9 billion, after tax. In addition, as a result of receiving a CPUC decision in the Utility's 2003 GRC, the Utility recorded various regulatory assets and liabilities associated with revenue requirement increases, recovery of retained generation assets and unfunded taxes, depreciation and decommissioning.

The following presents the Utility's operating results for 2004, 2003, and 2002.

Beginning January 1, 1998, electricity rates were frozen as required by the California electric industry restructuring law. In 2001, in response to the California energy crisis, the CPUC increased frozen rates by imposing fixed surcharges which the Utility collected through December 31, 2003. As a result of the Settlement Agreement and various CPUC decisions, the Utility's electricity rates as of January 1, 2004, are no longer frozen and are determined based on its costs of service.

As a result of the return to cost-of-service ratemaking in 2004, the Utility records its electric distribution revenues under revenue requirements approved by the 2003 GRC. Differences between the authorized revenue requirements and amounts collected by the Utility from customers in rates are tracked in regulatory balancing accounts and are reflected in miscellaneous revenues in the table below.

From mid-January 2001 through December 2002, the DWR was responsible for procuring electricity required to cover the Utility's net open position. The Utility resumed purchasing electricity on the open market in January 2003 to satisfy its residual net open position, but still relies on electricity provided under DWR contracts for a material portion of its customers' demand. Revenues collected on behalf of the DWR and the DWR's related costs are not included in the Utility's Consolidated Statements of Operations, reflecting the Utility's role as a billing and collection agent for the DWR's sales to the Utility's customers. Previously, under the frozen rate structure, increases in the revenues passed through to the DWR decreased the Utility's revenues. Starting in 2004, the Utility's electric operating revenues are based on an aggregation of individual rate components, including base revenue requirements, and electricity procurement costs, among others. Changes in the DWR's revenue requirements will not affect the Utility's revenues. Although the Utility is permitted to pass through the DWR charges to customers, any changes in the amount of DWR charges that the Utility's customers are required to pay can affect regulatory willingness to increase overall rates to permit the Utility to recover its own costs. As overall rates rise or decline, there may be changes regarding the risk of regulatory disallowance of costs.

The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio, including electricity provided under the DWR allocated contracts, in the most cost-effective way. This requirement, in certain cases, requires the Utility to schedule more electricity than is necessary to meet

its retail load and to sell this additional electricity on the open market. The Utility typically schedules excess electricity when the expected sales proceeds exceed the variable costs to operate a generation facility or buy electricity under an optional contract. Proceeds from the sale of surplus electricity are allocated between the Utility and the DWR based on the percentage of volume supplied by each entity to the Utility's total load. The Utility's net proceeds from the sale of surplus electricity after deducting the portion allocated to the DWR are recorded as a reduction to the cost of electricity.

The following table shows a breakdown of the Utility's electric operating revenues.

		2004			2003			2002
		(in millions)
Electric revenues		$	9,600		$	10,043		$	10,203
DWR pass-through revenue			(1,933	)		(2,243	)		(2,056	)
Subtotal			7,667			7,800			8,147
Miscellaneous			200			(218	)		31

	Total electric operating revenues	$	7,867		$	7,582		$	8,178

	Total electricity sales (in Kwh)⁽¹⁾		83,096			80,152			75,968

The Utility's electric operating revenues increased in 2004 by approximately $285 million, or approximately 4%, compared to 2003 due to the following factors:

Partially offsetting the increase in electric operating revenues was the absence of surcharge revenues in 2004 as a result of the return to cost of service ratemaking in 2004. The Utility collected $875 million in surcharge revenues in 2003.

In 2003, the Utility's electric operating revenues decreased approximately $596 million, or 7%, compared to 2002.

Partially offsetting this decrease was an increase of approximately $270 million for electric distribution operations as a result of the 2003 GRC.

The Utility's cost of electricity includes electricity purchase costs and the cost of fuel used by its owned generation facilities, but it excludes costs to operate its owned generation facilities, which are included in operating and maintenance expense. Electricity purchase costs and the cost of fuel used by owned generation facilities are passed through in rates to customers. The following table shows a breakdown of the Utility's cost of electricity and the total amount and average cost of purchased power, excluding in each case both the cost and volume of electricity provided by the DWR to the Utility's customers:

	2004			2003			2002
	(in millions)
Cost of purchased power	$	2,816		$	2,449		$	1,980
Proceeds from surplus sales allocated to the Utility		(192	)		(247	)		—
Fuel used in own generation		146			117			97
Adjustments to purchased power accruals		—			—			(595	)

Total net cost of electricity	$	2,770		$	2,319		$	1,482

Average cost of purchased power per kWh	$	0.082		$	0.076		$	0.081

Total purchased power (GWh)		34,525			32,249			24,552

In 2004, the Utility's cost of electricity increased approximately $451 million, or 19%, as compared to 2003 mainly due to the following factors:

In 2003, the Utility's cost of electricity increased approximately $837 million, or 56%, compared to 2002 mainly due to the following factors:

The Utility's cost of electricity in 2005 will depend upon electricity prices and the amount of the Utility's residual net open position (see the "Risk Factors" section of this MD&A).

The Utility sells natural gas and provides natural gas transportation services to its customers. The Utility's natural gas customers consist of two categories: core and noncore customers. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The noncore customer class is comprised of industrial and larger commercial natural gas customers. The Utility provides natural gas delivery services to all core and noncore customers connected to the Utility's system in its service territory. Core customers can purchase natural gas from alternate energy service providers or can elect to have the Utility provide both delivery service and natural gas supply. When the Utility provides both supply and delivery, the Utility refers to the service as natural gas bundled service. In 2004, core customers represented over 99% of the Utility's total customers and approximately 35% of its total natural gas deliveries, while noncore customers comprised less than 1% of the Utility's total customers and approximately 65% of its total natural gas deliveries.

The Utility's transportation system transports gas throughout California to the Utility's distribution system, which, in turn, delivers gas to end-use customers. Utility transportation and distribution services for all customers have historically been bundled or sold together at a combined rate.

The following table shows a breakdown of the Utility's natural gas operating revenues:

		2004		2003		2002
		(in millions)
Bundled natural gas revenues		$	2,943	$	2,572	$	2,020
Transportation service-only revenues			270		284		316

	Total natural gas operating revenues	$	3,213	$	2,856	$	2,336

Average bundled revenue per Mcf of natural gas sold		$	10.51	$	9.22	$	7.16

Total bundled natural gas sales (in millions of Mcf)			280		279		282

The Utility's natural gas operating revenues increased approximately $357 million, or 13%, for the year ended December 31, 2004, compared to 2003. The increase in natural gas operating revenues was primarily due to the following factors:

In 2003, the Utility's total natural gas operating revenues increased approximately $520 million, or 22%, compared to 2002. The Utility's bundled natural gas revenues increased by approximately $552 million, or 27%, in 2003 compared to 2002 mainly due to a higher average cost of natural gas, which the Utility is permitted by the CPUC to pass on to its customers through higher rates. The average bundled revenue per Mcf of natural gas sold in 2003 increased $2.06, or 29%, compared to 2002. This increase in bundled natural gas revenues was partially offset by a decrease in transportation service-only revenues of approximately $32 million, or 10%, in 2003 compared to 2002. The decrease in transportation service-only revenues was primarily due to a decrease in demand for natural gas transportation services by certain non-core customers, mainly natural gas-fired electric generators in California. An increase in electricity available from hydroelectric facilities and the greater efficiency of

generation facilities that commenced operations in 2003 resulted in reduced demand for natural gas transportation services.

The Utility's natural gas revenues in 2005 will increase due to an increase in natural gas distribution revenue requirements that were approved in the 2003 GRC decision, and will be further impacted by changes in the cost of natural gas.

The Utility's cost of natural gas includes the purchase cost of natural gas and transportation costs on interstate pipelines, but excludes the costs associated with the Utility's intrastate pipeline, which are included in operating and maintenance expense. The following table shows a breakdown of the Utility's cost of natural gas:

		2004		2003		2002
		(in millions)
Cost of natural gas sold		$	1,591	$	1,336	$	853
Cost of natural gas transportation			133		131		101

	Total cost of natural gas	$	1,724	$	1,467	$	954

Average cost per Mcf of natural gas sold		$	5.68	$	4.79	$	3.02

Total natural gas sold (in millions of Mcf)			280		279		282

In 2004 the Utility's total cost of natural gas increased approximately $257 million, or 18%, as compared to 2003, primarily due to an increase in the average market price of natural gas purchased of approximately $0.89 per Mcf.

In 2003, the Utility's total cost of natural gas increased by approximately $513 million, or 54%, compared to 2002 mainly due to the following factors:

The Utility's cost of natural gas sold in 2005 will be primarily affected by the prevailing costs of natural gas, which are determined by North American regions that supply the Utility.

Operating and maintenance expenses consist mainly of the Utility's costs to operate and maintain its electricity and natural gas facilities, customer accounts and service expenses, public purpose program expenses, and administrative and general expenses.

During 2004, the Utility's operating and maintenance expenses decreased by approximately $93 million, or 3%, compared to 2003. This decrease is primarily due to the establishment of a regulatory asset of approximately $50 million in 2004 related to distribution-related electric industry restructuring costs incurred during the period from 1999 through 2002 that were previously not considered probable of recovery. During 2004, the CPUC adopted a proposed settlement agreement that permits recovery of a portion of these costs (see the "Regulatory Matters" section of this MD&A).

In 2003, the Utility's operating and maintenance expenses increased by approximately $118 million, or 4%, compared to 2002 mainly due to a reversal of a liability of approximately $65 million for surcharge revenues in excess of ongoing procurement costs and surcharge revenue collections at the end of 2002. The remainder of the increase was mainly due to wage increases in 2003 and increases in employee benefit plan-related expenses due to a 15% decrease in returns on plan investments and a decrease in the discount rates used to calculate the present value of the Utility's benefit obligations from 6.75% to 6.25%.

In light of the satisfaction of various conditions to the implementation of the Utility's plan of reorganization, the Utility recorded the regulatory assets provided for under the Settlement Agreement in the first quarter of 2004. This resulted in the recognition of a one-time non-cash, pre-tax gain of $3.7 billion for the Settlement Regulatory Asset and $1.2 billion for the Utility retained generation regulatory assets, for a total after-tax gain of $2.9 billion. See the "Overview" section of this MD&A and Note 2 of the Notes to the Consolidated Financial Statements for further discussion.

The Utility charges the original cost of retired plant and removal costs less salvage value to accumulated depreciation upon retirement of plant in service for its lines of business that apply SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," as amended, or SFAS No. 71, which includes electricity and natural gas distribution, electricity generation and transmission, and natural gas transportation and storage.

In 2004, the Utility's depreciation, amortization and decommissioning expenses increased by approximately $276 million, or 23%, compared to 2003, primarily as a result of the amortization of the Settlement Regulatory Asset and an increase in the Utility's plant assets.

In 2003, the Utility's depreciation, amortization and decommissioning expenses increased by approximately $25 million, or 2%, compared to 2002 mainly due to an increase in the Utility's plant assets.

In accordance with the American Institute of Certified Public Accountants' Statement of Position 90-7, "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code," or SOP 90-7, the Utility reports reorganization fees and expenses separately on its Consolidated Statements of Operations. These costs mainly include professional fees for services in connection with the Utility's Chapter 11 proceedings and totaled approximately $6 million in 2004, $160 million in 2003 and $155 million in 2002. The Utility discontinued reporting in accordance with SOP 90-7 upon its emergence from Chapter 11 on April 12, 2004.

In accordance with SOP 90-7, the Utility reports reorganization interest income separately on its Consolidated Statements of Operations. Reorganization interest income mainly includes interest earned on cash accumulated during the Utility's Chapter 11 proceedings. Interest income, including reorganization interest income, decreased by approximately $3 million, or 6%, in 2004 from 2003 and approximately $21 million, or 28%, in 2003 from 2002. Both decreases were mainly due to lower average interest rates earned on the Utility's short-term investments.

In 2004, the Utility's interest expense decreased by approximately $286 million, or 30%, compared to 2003 mainly due to a lower average amount of unpaid debt accruing interest and a lower weighted average interest rate on debt outstanding during 2004 compared to 2003. As a result of this interest savings, the CPUC reduced the Utility's authorized cost of capital revenue requirement in 2004 (see the "Regulatory Matters" section of this MD&A).

In 2003, the Utility's interest expense decreased by approximately $35 million, or 4%, compared to 2002 mainly due to the reduction in the amount of rate reduction bonds outstanding, reflecting the declining principal balance of the rate reduction bonds and a lower amount of unpaid debts accruing interest. See Note 3 of the Notes to the Consolidated Financial Statements for further discussion. This decrease was partially offset by the accrual of $38 million in interest payable to the DWR in 2003.

In 2004, the Utility's income tax expense increased by approximately $2.0 billion, or 387%, as compared to 2003, mainly due to an increase in pre-tax income of approximately $5.1 billion for the year ended December 31, 2004, primarily as a result of the recognition of regulatory assets associated with the Settlement Agreement, as compared to the same period in 2003. This increase was partially offset by the recognition of tax regulatory assets established upon receipt of the Utility's 2003 GRC decision. The effective tax rate for the year ended December 31, 2004 increased by 2.9 percentage points. This increase is due mainly to increases in the effect of regulatory treatment of depreciation differences and lower tax credit amortization in 2004.

In 2003, the Utility's income tax expense decreased by approximately $650 million, or 55%, as compared to 2002, mainly due to a decrease in pre-tax income of approximately $1.5 billion for the year ended December 31, 2003. In 2003 the effective tax rate decreased by 2.9 percentage points from 2002. The decrease is due mainly to the effect of regulatory treatment of depreciation differences.

PG&E Corporation's revenues consist mainly of billings to its affiliates for services rendered, all of which are eliminated in consolidation. PG&E Corporation's operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation's operating expenses are allocated to affiliates. These allocations are made without mark-up. Operating expenses allocated to affiliates are eliminated in consolidation.

The increase in operating expenses was primarily due to the absence of entries in 2004 to eliminate the cost of natural gas and electricity expenses provided by NEGT to the Utility after PG&E Corporation's deconsolidation of NEGT effective July 7, 2003. A reduction in general and administrative expenses in 2004 compared to 2003 partly offset this increase.

In 2003, the increase in operating expenses of approximately $43 million compared to the same period in 2002, was primarily attributable to increased employee compensation plan expenses, partly offset by a decrease in consulting services and outside attorney fees related to the Utility's plan of reorganization.

PG&E Corporation's interest expense is not allocated to its affiliates. In 2004, PG&E Corporation's interest expense decreased by approximately $64 million, or 33%, compared to 2003 due to a reduction in principal debt amount outstanding and lower interest rates in 2004 compared to 2003, as well as a write-off of approximately $89 million of unamortized loan fees, loan discount, and

prepayment fees associated with the repayment in July 2003 of approximately $735 million of principal and interest under PG&E Corporation's then existing credit agreement. This decrease in interest expense was partly offset by a redemption premium of approximately $51 million and a charge due to the write-off of approximately $15 million of unamortized loan fees associated with the redemption of PG&E Corporation's $600 million of 6⁷/8% Senior Secured Notes due 2008, or Senior Secured Notes, on November 15, 2004.

In 2003, PG&E Corporation's interest expense decreased by approximately $42 million, or 18%, compared to 2002. The decrease was mainly due to a decrease in amortization of deferred charges and unamortized loan fees during 2003, compared to 2002. During the third quarter of 2003, PG&E Corporation wrote off approximately $89 million as described above, while during the third quarter of 2002, PG&E Corporation wrote off $153 million of unamortized loan fees and discounts when it repaid principal and modified a loan under PG&E Corporation's credit agreement.

PG&E Corporation's other expense increased by approximately $93 million in 2004 compared to 2003. The increase was primarily due to a pre-tax charge to earnings, related to the change in market value of non-cumulative dividend participation rights included within PG&E Corporation's $280 million of 9.50% Convertible Subordinated Notes due 2010, or Convertible Subordinated Notes.

In 2003, PG&E Corporation's other income decreased by approximately $77 million, compared to 2002, due to the third quarter of 2002 change in the market value of NEGT warrants. In 2001, PG&E Corporation granted to affiliates of lenders through which it was refinancing debt, warrants to purchase up to 2% or 3% of NEGT's outstanding common stock (depending on how long the loans were outstanding). These warrants were originally recorded at their fair value of approximately $151 million. The fair value of the warrants was marked to market at the end of each reporting period. Changes in fair value of the warrants were recorded as other non-operating expense or income. In the third quarter of 2002, approximately $71 million was recorded in other non-operating income to reflect the reduction to zero of the fair value of the 3% warrants. The 3% warrants were exercised during the first quarter of 2003.

Effective July 8, 2003 (the date NEGT filed a voluntary petition for relief under Chapter 11), NEGT and its subsidiaries were no longer consolidated by PG&E Corporation in its Consolidated Financial Statements. Under accounting principles generally accepted in the United States of America, or GAAP, consolidation is generally required for entities owning more than 50% of the outstanding voting stock of an investee, except when control is not held by the majority owner. Legal reorganization and bankruptcy represent conditions that can preclude consolidation in instances where control rests with an entity other than the majority owner. In anticipation of NEGT's Chapter 11 filing, PG&E Corporation's representatives who previously served on the NEGT Board of Directors resigned on July 7, 2003, and were replaced with Board members who are not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retained significant influence over the ongoing operations of NEGT.

Accordingly, PG&E Corporation has reflected the loss from operations of NEGT through July 7, 2003 as discontinued operations in its Consolidated Statements of Operations. In addition, PG&E Corporation's negative investment in NEGT of approximately $1.2 billion was reflected as a single amount, under the cost method, within the December 31, 2003 Consolidated Balance Sheet of PG&E Corporation. This negative investment represents the losses of NEGT recognized by PG&E Corporation in excess of its investment in and advances to NEGT.

On October 29, 2004, NEGT's plan of reorganization became effective, at which time NEGT emerged from Chapter 11 and PG&E Corporation's equity ownership in NEGT was cancelled. On the

effective date, PG&E Corporation reversed its negative investment in NEGT and also reversed net deferred income tax assets of approximately $428 million and a charge of approximately $120 million ($77 million, after tax), in accumulated other comprehensive income, related to NEGT. The resulting net gain has been offset by the $30 million payment made by PG&E Corporation to NEGT pursuant to the parties' settlement of certain tax-related litigation and other adjustments to NEGT-related liabilities. A summary of the effect on the quarter and year ended December 31, 2004 earnings from discontinued operations is as follows:

	(in millions)
Investment in NEGT	$	1,208
Accumulated other comprehensive income		(120	)
Cash paid pursuant to settlement of tax related litigation		(30	)
Tax effect		(374	)

Gain on disposal of NEGT, net of tax	$	684

At December 31, 2004, PG&E Corporation's Consolidated Balance Sheet includes approximately $138 million in income tax liabilities (including $86 million in current income taxes payable) and approximately $25 million of other net liabilities related to NEGT. Until PG&E Corporation reaches final settlement of these obligations, it will continue to disclose fluctuations in these estimated liabilities in discontinued operations. Beginning on the effective date of NEGT's plan of reorganization, PG&E Corporation no longer includes NEGT or its subsidiaries in its consolidated income tax returns.

PG&E Corporation recorded losses from discontinued operations of approximately $365 million in 2003 and approximately $2.5 billion in 2002.

The level of PG&E Corporation and the Utility's current assets and current liabilities is subject to fluctuation as a result of seasonal demand for electricity and natural gas, energy commodity costs, and the timing and effect of regulatory decisions and financings, among other factors. The Utility will use the proceeds of the issuance of the ERBs it received from PERF, the issuer of the ERBs, to refinance the remaining unamortized balance of the Settlement Regulatory Asset through the redemption and repurchase of higher cost equity and debt. The Utility plans to use a portion of the ERB proceeds to defease $600 million of Floating Rate First Mortgage Bonds by the end of February 2005, retire $300 million of short-term debt, and repurchase approximately $960 million of its common stock from PG&E Corporation.

In January 2005, the equity component of the Utility's capital structure reached 52%, the target specified in the Settlement Agreement. As discussed below, on February 16, 2005, the Boards of Directors of the Utility and PG&E Corporation each declared a common stock dividend. In addition, PG&E Corporation anticipates that it will repurchase shares of its common stock of up to $1.05 billion, increased from a previous authorization of up to $975 million.

PG&E Corporation and the Utility intend to retain sufficient cash for operating needs and to manage debt levels to maintain access to credit. Available cash, combined with cash from operations and cash generated from refinancing of the Settlement Regulatory Asset will be used for planned capital expenditures and repayment of existing long-term debt. Surplus cash either will be returned to investors through dividend payments and/or share repurchases or utilized to fund incremental capital investments.

PG&E Corporation and the Utility seek to manage their liquidity and capital resources within the following parameters and assumptions:

At December 31, 2004, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately $1.0 billion, and restricted cash of approximately $2.0 billion. PG&E Corporation and the Utility maintain separate bank accounts. At December 31, 2004, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately $189 million. At December 31, 2004, the Utility had cash and cash equivalents of approximately $783 million, and restricted cash of approximately $2.0 billion. The Utility's restricted cash includes amounts deposited in escrow related to the remaining disputed Chapter 11 claims, collateral required by the ISO and deposits under certain third party agreements. PG&E Corporation and the Utility primarily invest their cash in money market funds and in short-term obligations of the U.S. Government and its agencies.

PG&E Corporation and the Utility did not declare or pay a dividend during the Utility's Chapter 11 proceeding as the Utility was prohibited from paying any common or preferred stock dividends without bankruptcy court approval and certain covenants in PG&E Corporation's Senior Secured Notes restricted the circumstances in which such a dividend could be declared or paid. With the Utility's emergence from Chapter 11 on April 12, 2004, the Utility resumed the payment of preferred stock dividends.

On February 16, 2005, the Board of Directors of the Utility declared a cash dividend of $117 million on the Utility's common stock for the first quarter of 2005. The dividend was paid to PG&E Corporation and PG&E Holdings LLC, a wholly owned subsidiary of the Utility that holds

approximately 6% of the Utility's common stock, on February 17, 2005. Also, on February 16, 2005, the Board of Directors of PG&E Corporation declared a cash dividend of $0.30 per share on PG&E Corporation's common stock for the first quarter of 2005, payable on April 15, 2005, to shareholders of record on March 31, 2005. These actions are consistent with the dividend policy and target dividend payout ratio range (the proportion of earnings paid out as dividends) adopted by both Boards in October 2004. PG&E Corporation's and the Utility's dividend policies contemplate a target dividend payout ratio range of 50-70% and PG&E Corporation's policy targets an initial annual cash dividend of $1.20 per share ($0.30 quarterly).

PG&E Corporation's and the Utility's dividend policies are designed to meet the following three objectives:

The target dividend payout ratio range was based on an analysis of dividend payout ratios of comparable companies. The initial dividend target was chosen in recognition of the Utility's current credit rating and the potential capital investments that the Utility may make in the future to provide electricity resource adequacy in compliance with future regulatory requirements and an approved LTPP.

Each Board of Directors retains authority to change its common stock dividend policy and its dividend payout ratio at any time, especially if unexpected events occur that would change the Board's views as to the prudent level of cash conservation.

During the fourth quarter of 2004, 1,863,600 shares of PG&E Corporation common stock were repurchased through transactions with brokers and dealers on the New York Stock Exchange and/or the Pacific Exchange for an aggregate purchase price of approximately $60 million. Of this amount, 850,000 shares are held by Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.

In addition, on December 15, 2004, PG&E Corporation entered into accelerated share repurchase arrangements with Goldman, Sachs & Co., or GS&Co., under which PG&E Corporation repurchased 9,769,600 shares of its common stock for an aggregate of purchase price of approximately $318 million. The repurchased shares were retired. PG&E Corporation will pay GS&Co. approximately $14 million on February 22, 2005, to settle its obligations to pay GS&Co. a price adjustment based on the daily volume weighted average market price of PG&E Corporation common stock over the term of the arrangement.

On December 15, 2004, the Board of Directors of the Utility authorized the repurchase of up to $800 million (which has been increased to $1.8 billion following the receipt of proceeds from the issuance of ERBs) of the Utility's common stock from PG&E Corporation, with such repurchases to be effective from time to time, but no later than December 31, 2006. Based on the expected receipt of funds, on December 15, 2004, PG&E Corporation's Board of Directors authorized the repurchase of up to $975 million of its outstanding common stock.

On February 16, 2005, the Board of Directors of PG&E Corporation increased this authorization to $1.05 billion with such repurchases to be effected from time to time, but no later than June 30,

2006. PG&E Corporation expects to enter into a replacement accelerated share repurchase arrangement by early March 2005 to repurchase an aggregate of $1.05 billion of its outstanding shares. The repurchased shares will be retired at that time.

The Utility's cash flows from operating activities consist of sales to its customers and payments of operating expenses, other than expenses such as depreciation that do not require the use of cash. Cash flows from operating activities are also impacted by collections of accounts receivable and payments of liabilities previously recorded.

The Utility's cash flows from operating activities for 2004, 2003 and 2002 were as follows:

In 2004, net cash provided by operating activities approximated 2003 levels. This is mainly due to the following factors:

In 2003, net cash provided by operating activities increased by approximately $836 million compared to 2002, even though net income decreased by $896 million in 2003. This is mainly due to the following factors:

The Utility's investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash flows from operating activities have been sufficient to fund the Utility's capital expenditure requirements during 2004, 2003 and 2002. Year to year variances depend upon the amount and type of construction activities, which can be influenced by storm and other damage.

The Utility's cash flows from investing activities for 2004, 2003 and 2002 were as follows:

		2004			2003			2002
		(in millions)
Capital expenditures		$	(1,559	)	$	(1,698	)	$	(1,546	)
Net proceeds from sale of assets			35			49			11
Increase in restricted cash			(1,710	)		—			—
Other investing activities, net			(178	)		(114	)		26

	Net cash used by investing activities	$	(3,412	)	$	(1,763	)	$	(1,509	)

In 2004, net cash used by investing activities increased by approximately $1.6 billion as compared to 2003. This increase was mainly due to an increase in restricted cash of approximately $1.7 billion in 2004 reflecting a deposit of funds into an escrow account to pay disputed Chapter 11 claims when resolved. This was partially offset by a decrease of $139 million in capital expenditures in 2004 compared to 2003 primarily due to delays in electric transmission line capacity projects.

In 2003, net cash used by investing activities increased by approximately $254 million compared to 2002. This increase was mainly due to an increase in capital expenditures related to electricity transmission network upgrades and new electricity capacity and transmission development projects in 2003 and other investing activities during 2003. Cash flows from other investing activities related mainly to nuclear decommissioning funding and the change in nuclear fuel inventory during the period.

During its Chapter 11 proceeding, the Utility's financing activities were limited to repayment of secured debt obligations as authorized by the bankruptcy court. During this period, the Utility did not have access to the capital markets. In March 2004, in anticipation of its emergence from Chapter 11, the Utility issued significant amounts of debt in order to finance its payments to be made in connection with the implementation of the plan of reorganization on the Effective Date. The Utility also established a working capital facility and an accounts receivable financing facility for the purposes of funding its operating expenses and seasonal fluctuations in working capital and providing letters of credit.

The Utility's cash flows from financing activities for 2004, 2003 and 2002 were as follows:

		2004			2003			2002
		(in millions)
Net proceeds from long-term debt issued		$	7,742		$	—		$	—
Net proceeds under credit facilities and short-term borrowings			300			—			—
Rate reduction bonds matured			(290	)		(290	)		(290	)
Long-term debt, matured, redeemed or repurchased			(8,402	)		(281	)		(333	)
Preferred dividends paid			(90	)		—			—
Preferred stock redeemed			(15	)		—			—

	Net cash used by financing activities	$	(755	)	$	(571	)	$	(623	)

In 2004, net cash used by financing activities increased by approximately $184 million as compared to 2003. This was mainly due to the following factors:

In 2003, net cash used by financing activities decreased by approximately $52 million compared to 2002. With bankruptcy court approval, the Utility repaid approximately $281 million in principal on its mortgage bonds that matured in August 2003, which was a decrease of approximately $52 million from 2002.

PG&E Funding, LLC, a wholly owned subsidiary of the Utility, also repaid approximately $290 million in principal on its rate reduction bonds in 2003 and 2002. PG&E Funding, LLC was not included in the Utility's Chapter 11 proceeding. PG&E Funding, LLC pays the principal and interest on the rate reduction bonds from a specific rate element in Utility customers' bills. See Note 4 of the Notes to the Consolidated Financial Statements for further discussion. The Utility remits the collection of these billings to PG&E Funding, LLC on a daily basis.

As of December 31, 2004, PG&E Corporation had stand-alone cash and cash equivalents of approximately $189 million. PG&E Corporation's sources of funds are dividends and share repurchases from the Utility, issuance of its common stock and external financing. The Utility did not pay any dividends to, nor repurchase shares from, PG&E Corporation during 2004, 2003, or 2002.

PG&E Corporation's consolidated cash flows from operating activities consist mainly of billings to the Utility for services rendered and payments for employee compensation and goods and services provided by others to PG&E Corporation. PG&E Corporation also incurs interest costs associated with its debt.

PG&E Corporation's consolidated cash flows from operating activities for 2004, 2003 and 2002 were as follows:

			2004			2003			2002
			(in millions)
Net income (loss)			$	4,504		$	420		$	(874	)
Gain on disposal of NEGT (net of income taxes of $374 million)				(684	)		—			—
Loss from discontinued operations				—			365			2,536
Cumulative effect of changes in accounting principles				—			6			61

Net income from continuing operations				3,820			791			1,723
Non-cash (income) expenses:
	Depreciation, amortization and decommissioning			1,497			1,222			1,196
	Deferred income taxes and tax credits—net			611			190			(281	)
	Recognition of regulatory asset, net of tax			(2,904	)		—			—
	Other deferred charges and noncurrent liabilities			(519	)		857			921
	Loss from retirement of long-term debt			65			89			153
	Gain of sale of assets			(19	)		(29	)		—
	Tax benefit from employee stock plans			41			—			—
Other changes in operating assets and liabilities:				(242	)		(618	)		(2,898	)

		Net cash provided by operating activities	$	2,350		$	2,502		$	814

In 2004 the net cash provided by operating activities decreased by $152 million, compared to 2003 due to 2004 payments totaling approximately $85 million for PG&E Corporation's senior executive retention program and $30 million pursuant to a settlement of certain tax-related litigation between PG&E Corporation and NEGT. There were no similar payments in the prior year.

In 2003, PG&E Corporation's consolidated cash flows provided by operating activities increased by approximately $1.7 billion compared to 2002, mainly due to an increase in the Utility's net cash provided from operating activities, partially offset by a decrease in net cash provided from NEGT's operating activities as a result of realized losses generated through July 7, 2003.

PG&E Corporation, on a stand-alone basis, did not have any material investing activities in the years ended December 31, 2004, 2003 and 2002.

PG&E Corporation's cash flows from financing activities consist mainly of cash generated from debt refinancing and the issuance of common stock.

PG&E Corporation's cash flows from financing activities for 2004, 2003 and 2002 were as follows:

		2004			2003			2002
		(in millions)
Net borrowings under credit facilities and short-term borrowings		$	300		$	—		$	—
Net proceeds from long-term debt issued			7,742			581			847
Long-term debt matured, redeemed or repurchased			(9,054	)		(1,068	)		(1,241	)
Rate reduction bonds matured			(290	)		(290	)		(290	)
Preferred stock with mandatory redemption provisions redeemed			(15	)		—			—
Common stock issued			162			166			217
Common stock repurchased			(378	)		—			—
Preferred dividends paid			(90	)		—			—
Other, net			(1	)		(4	)		—

	Net cash used by financing activities	$	(1,624	)	$	(615	)	$	(467	)

In 2004, PG&E Corporation's consolidated net cash used by financing activities increased by approximately $1,009 million, compared to 2003. The increase is primarily due to the November 15, 2004 redemption of PG&E Corporation's Senior Secured Notes for which PG&E Corporation paid approximately $664.5 million which included a redemption premium of approximately $50.7 million and $13.8 million of interest accrued since the last interest payment date. During November and December of 2004, PG&E Corporation repurchased 10,783,200 shares of PG&E Corporation common stock at a cost of approximately $350 million and 850,000 shares repurchased through Elm Power Corporation, PG&E Corporation's subsidiary, at a value of $28 million.

In 2003, net cash used by financing activities increased by $148 million compared to 2002 mainly due to a decrease in common stock issued for 401(k) plan stock purchases and stock option and warrant exercises and a decrease in net proceeds from long-term debt issued. In 2002, PG&E Corporation refinanced a credit facility, which was further amended to increase the size of the facility in October 2002 to a total of $720 million. In addition, in June 2002, PG&E Corporation issued $280 million of Convertible Subordinated Notes. In July 2003, PG&E Corporation issued $600 million of Senior Secured Notes.

The following table provides information about the Utility's and PG&E Corporation's contractual obligations and commitments at December 31, 2004. PG&E Corporation and the Utility enter into contractual obligations in connection with business activities. These obligations primarily relate to financing arrangements (such as long-term debt, preferred stock and certain forms of regulatory

financing), purchases of transportation capacity, natural gas and electricity to support customer demand and the purchase of fuel and transportation to support the Utility's generation activities.

The Utility's contractual commitments include power purchase agreements (including agreements with qualifying facilities, irrigation districts and water agencies and renewable energy providers), natural gas supply and transportation agreements, nuclear fuel agreements, operating leases and other commitments.

Qualifying Facility Power Purchase Agreements—The Utility is required by CPUC decisions to purchase energy and capacity from independent power producers that are qualifying facilities under the Public Utility Regulatory Policies Act of 1978, or PURPA. To implement PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with qualifying facilities and approved the applicable terms, conditions, prices and eligibility requirements. These agreements require the Utility to pay for energy and capacity. Energy payments are based on the qualifying facility's actual electrical output and CPUC-approved energy prices, while capacity payments are based on the qualifying facility's total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the qualifying facility fails to meet or exceeds performance requirements specified in the applicable power purchase agreement.

As of December 31, 2004, the Utility had agreements with 300 qualifying facilities for approximately 4,300 megawatts, or MW, that are in operation. Agreements for approximately 3,950 MW expire at various dates between 2005 and 2028. Qualifying facility power purchase agreements for approximately 350 MW have no specific expiration dates and will terminate only when the owner of the qualifying facility exercises its termination option. The Utility also has power purchase agreements with approximately 50 inoperative qualifying facilities. The total of approximately 4,300 MW consists of approximately 2,600 MW from cogeneration projects, 700 MW from wind projects and 1,000 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar and hydroelectric.

On January 22, 2004, the CPUC ordered the California investor-owned electric utilities to allow owners of qualifying facilities with certain power purchase agreements expiring before the end of 2005 to extend these contracts for five years with modified pricing terms. As of December 31, 2004, thirteen qualifying facilities had entered into such five-year contract extensions. Qualifying facility power purchase agreements accounted for approximately 23% of the Utility's 2004 electricity sources, approximately 20% of the Utility's 2003 electricity sources, and approximately 25% of the Utility's 2002 electricity sources. No single qualifying facility accounted for more than 5% of the Utility's 2004, 2003 or 2002 electricity sources.

There are proceedings pending at the CPUC that may impact both the amount of payments to qualifying facilities and the number of qualifying facilities holding power purchase agreements with the Utility. The CPUC will address whether certain payments for short-term power deliveries required by the power purchase agreements comply with the pricing requirements of the PURPA. The CPUC is also considering whether to require the California investor-owned electric utilities to enter into new power purchase agreements with existing qualifying facilities with expiring power purchase agreements and with newly-constructed qualifying facilities. PG&E Corporation and the Utility are unable to estimate the outcome of these proceedings.

In a proceeding pending at the CPUC, the Utility has requested refunds in excess of $500 million for overpayments from June 2000 through March 2001 that were made to qualifying facilities pursuant to CPUC orders at approved rates. The net after-tax amount of any qualifying facilities refunds, which the Utility actually realizes in cash, claim offsets or other credits, would be credited to customers, either as a reduction to the principal amount of the second series of ERBs anticipated to be issued in November 2005, or if refunds are received after the second series of ERBs is issued, as a credit to the balancing account that tracks recovery of the customer costs and benefits related to the ERBs. PG&E Corporation and the Utility are unable to estimate the outcome of this proceeding.

Irrigation Districts and Water Agencies—The Utility has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts' and water agencies' debt service requirements, regardless if any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2005 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 5% of the Utility's 2004 electricity sources, approximately 5% of the Utility's 2003 electricity sources and approximately 4% of the Utility's 2002 electricity sources.

Electricity Purchases to Satisfy the Residual Net Open Position—In 2004 the Utility continued buying electricity to meet its residual net open position. During 2004, more than 10,000 Gigawatt hours, or GWh, of energy was bought and sold in the wholesale market to manage the 2004 residual net open position. Most of the Utility's contracts entered into in 2004 had terms of less than one year. In 2004, the Utility both submitted and requested bids in competitive solicitations to meet intermediate and long-term needs and anticipates procuring electricity under contracts with multi-year terms beginning in 2005.

Renewable Energy Requirement—California law requires that, beginning in 2003, each California retail seller of electricity, except for municipal utilities, must increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year, the annual procurement target, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. The Utility was excused from meeting its annual procurement target under the current law in 2003 and 2004 due to its Chapter 11 proceeding. With its exit from Chapter 11, as of January 1, 2005, the Utility is no longer exempt from complying with its annual procurement target. To meet the 20% goal by the end of 2017, the Utility estimates that it will need to purchase 700-800 GWh of electricity from renewable resources each year. During 2003 and 2004, the Utility entered into several new renewable power purchase contracts that will help the Utility meet its goals. The Utility also is conducting negotiations with several renewable energy providers pursuant to a request for offers made by the Utility in July 2004 that should result in the Utility entering into a number of new renewable contracts in 2005. In January 2005, the California Senate introduced a bill proposing to require the goal to be met by the end of 2010 instead of 2017. The CPUC also has suggested that the 20% goal be met by 2010. The Utility estimates that the accelerated goal would require the Utility to increase the amount of its annual renewable energy

purchases to approximately 800-900 GWh. Based on the medium load scenario in the Utility's long-term electricity procurement plan, the Utility believes that it can meet the accelerated goal.

Annual Receipts and Payments—The payments made under qualifying facility, irrigation district, water agency and bilateral agreements during 2002 through 2004 were as follows:

	2004		2003		2002
	(in millions)
Qualifying facility energy payments	$	1,002	$	994	$	1,051
Qualifying facility capacity payments		487		499		506
Irrigation district and water agency payments		61		62		57
Other power purchase agreement payments		834		513		196

At December 31, 2004, the undiscounted future expected power purchase agreement payments were as follows:

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers. The contract lengths and natural gas sources of the Utility's portfolio of natural gas procurement contracts has fluctuated, generally based on market conditions.

During the period that the Utility was in Chapter 11, the Utility used several different credit arrangements to purchase natural gas, including a $10 million cash collateralized standby letter of credit and a pledge of its core natural gas customer accounts receivable. In connection with its emergence from Chapter 11, the Utility received investment grade issuer credit ratings from Moody's and S&P. As a result of these credit rating upgrades, the Utility has obtained unsecured credit lines from the majority of its gas supply counterparties.

At December 31, 2004, the Utility's obligations for natural gas purchases and gas transportation services were as follows:

Payments for natural gas purchases and gas transportation services amounted to approximately $1.8 billion in 2004, $1.5 billion in 2003, and $898 million in 2002.

The Utility has purchase agreements for nuclear fuel. These agreements have terms ranging from two to eight years and are intended to ensure long-term fuel supply. Deliveries under 9 of the 11 contracts in place at the end of 2003 were completed by 2004. New contracts for deliveries in 2005 to 2012 are under negotiation. In most cases, the Utility's nuclear fuel contracts are requirements-based. The Utility relies on large, well-established international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms also are diversified, ranging from fixed prices to market-based prices to base prices that are escalated using published indices.

At December 31, 2004, the undiscounted obligations under nuclear fuel agreements were as follows:

Payments for nuclear fuel amounted to approximately $119 million in 2004, $57 million in 2003 and $70 million in 2002.

The ISO has entered into reliability must run, or RMR, agreements with various power plant owners, including the Utility, that require designated units in certain power plants, known as RMR plants, to remain available to generate electricity upon the ISO's demand when needed for local transmission system reliability. At December 31, 2004, as a party to the Transmission Control Agreement, or the TCA, the Utility estimated that it could be obligated to pay the ISO approximately $570 million in costs incurred under these RMR agreements during the period January 1, 2005 to December 31, 2006. Of this amount, the Utility estimates that it would receive approximately $42 million under its RMR agreements during the same period. These costs and revenues are subject to applicable ratemaking mechanisms.

In June 2000, a FERC administrative law judge, or ALJ, issued an initial decision addressing subsidiaries of Mirant Corporation. The decision approved rates and a ratemaking methodology that, if affirmed by the FERC, will require the Mirant subsidiaries that are parties to three RMR agreements with the ISO to refund to the ISO, and the ISO to refund to the Utility, excess payments of approximately $360 million, including interest, for the availability of Mirant's RMR plants under these agreements. On July 14, 2003, Mirant filed a petition for reorganization under Chapter 11 and on December 15, 2003, the Utility filed claims in Mirant's Chapter 11 proceeding, including a claim for an RMR refund. On January 14, 2005, the Utility entered into a settlement with Mirant and its subsidiaries that own RMR units that will resolve the Utility's claim through September 30, 2004. The settlement agreement is subject to approval by the FERC, the bankruptcy court overseeing the Chapter 11 cases filed by Mirant and these subsidiaries, and, to the extent deemed necessary by the Utility, by the bankruptcy court that retains jurisdiction over the Utility's Chapter 11 case. Under the settlement, Mirant will transfer to the Utility Mirant's interest in and equipment for the partially built Contra Costa Unit 8 power plant. If Contra Costa Unit 8 is not transferred to the Utility as a result of various

contingencies described in the settlement, Mirant will pay the Utility at least $70 million in lieu of the plant assets. In addition, under the settlement, the Utility will enter into a contract that gives the Utility the right to dispatch power from certain RMR units owned by Mirant subsidiaries from 2006-2012, and the Utility will receive approximately $60 million of allowed claims, credits, offsets, or cash from Mirant or its subsidiaries. The Utility is unable to predict whether and when the FERC or the bankruptcy courts will approve the settlement. Although the settlement resolves issues concerning any refund that might be owed by Mirant, it does not address the underlying merits of the RMR case, which will still be decided by the FERC.

In November 2001, after the ALJ issued the initial decision in Mirant's rate case, two complaints were filed at the FERC against other RMR plant owners, including the Utility, alleging that the ratemaking methodology approved in the ALJ's initial decision should be applied to the other RMR agreements. The complainants asked the FERC to take no action until after the FERC issues its final decision in Mirant's rate case. If the FERC adopts the ALJ's decision in the Mirant rate case and applies the ratemaking methodology to the Utility's RMR plants, the Utility could be required to refund payments it received from the ISO for the availability of the Utility's RMR plants. The Utility has responded to the complaint asserting that the methodology approved in the ALJ's decision should not apply to the Utility. The FERC has not yet acted on these complaints. On December 23, 2004, the Utility filed a settlement with all the complainants that, if approved by FERC, will result in the withdrawal of the complaint with no decision by the FERC on its merits. If the case is not dismissed, the Utility believes the ultimate outcome of this matter will not have an adverse material effect on the Utility's results of operations or financial condition.

The Utility has other commitments relating to operating leases, capital infusion agreements, equipment replacements, the self-generation incentive program exchange agreements and telecommunication contracts. At December 31, 2004, the future minimum payments related to other commitments were as follows:

Payments for other commitments amounted to approximately $111 million in 2004, $74 million in 2003, and $34 million in 2002.

The Utility's current commitments under financing arrangements include obligations to repay First Mortgage Bonds, pollution control bond-related agreements, credit facilities and reimbursement agreements associated with letters of credit.

In addition, PG&E Funding, LLC must make scheduled payments on its rate reduction bonds. The balance owed on these bonds at December 31, 2004 was approximately $870 million. Annual principal payments on the rate reduction bonds total approximately $290 million. The rate reduction bonds are expected to be fully retired by the end of 2007.

A detailed description of these commitments is included in Note 3 and Note 4 of the Notes to the Consolidated Financial Statements.

The Utility's investment in plant and equipment totaled approximately $1.6 billion in 2004, $1.7 billion in 2003 and $1.5 billion in 2002. The Utility's annual capital expenditures are expected to increase to an average of approximately $2.0 billion annually over the next five years. These expenditures are necessary to replace aging and obsolete equipment and accommodate anticipated electricity and natural gas load growth of approximately 2% and 1.2% per year, respectively. Capital expenditures for which contracts or firm commitments exist have, in addition to being included in estimated capital expenditures, been included in the "Contractual Commitments" table above, which details the Utility's contractual obligations and commitments at December 31, 2004. The estimate of capital expenditures over the next five years includes the following significant capital expenditure projects:

The Utility retains the ability to delay or defer substantial amounts of these planned expenditures in light of changing economic conditions and changing technology. It is also possible that these projects may be replaced by other projects. Consistent with past practice, the Utility expects that any capital expenditures will be included in its rate base and recoverable in rates. Based on the estimate of average capital expenditures of approximately $2.0 billion annually over the next five years, the Utility's average annual rate base would grow by approximately 4.5% per year over the five-year period.

The Utility's residual net open position is expected to increase over time. To meet this need, the Utility will need to enter into contracts with third-party generators for additional supplies of electricity, develop or otherwise acquire additional generation facilities or satisfy its residual net open position through a combination of the two. The discussion above does not include any capital expenditures for new generation facilities aside from the Contra Costa project described above. The discussion above also does not include any capital expenditures necessary to implement advanced metering improvements.

The estimate of capital expenditures discussed above does not include up to $2.0 billion in additional potential expenditures over the 2005 through 2009 period for:

The Utility has estimated that if these additional capital expenditures related to new generation, electric transmission and distribution and gas distribution are made, the Utility's total weighted average rate base would grow by approximately 6.5% over the five-year period.

The CPUC is assessing the viability of implementing an advanced metering infrastructure for residential and small commercial customers. This infrastructure would enable the California investor-owned electric utilities to measure usage of electricity on a time-of-use basis and to charge demand responsive rates. The goal of demand responsive rates is to encourage customers to reduce energy consumption during peak demand periods and reduce peak period procurement costs. Advanced meters can record usage in time intervals and be read remotely. The Utility is implementing demand responsive tariffs for large industrial customers who already have advanced metering systems in place, and has just completed the second year of a statewide pilot program designed to test whether and how much residential and small commercial customers will respond to demand responsive rates. The Utility expects to provide information to the CPUC in the first quarter of 2005 regarding the results of this pilot program. If the CPUC determines that it would be cost-effective to install advanced metering on a large-scale and authorizes the Utility to proceed with large scale development of advanced metering for residential and small commercial customers, the Utility expects that it would incur substantial costs to convert its meters, build the meter reading network, and build the data storage and processing facilities to bill its customers. The Utility would expect to recover through rates the capital investments and any ongoing operating costs associated with implementing the advanced metering improvements. The total deployment of an advanced metering infrastructure to all of the Utility's electricity and natural gas customers using equipment and technology currently available may cost more than $1.0 billion, based on a five-year installation schedule starting in 2006.

For financing and other business purposes, PG&E Corporation and the Utility utilize certain arrangements that are not reflected in their Consolidated Balance Sheets. Such arrangements do not represent a significant part of either PG&E Corporation's or the Utility's activities or a significant ongoing source of financing. These arrangements are used to enable PG&E Corporation or the Utility to obtain financing or execute commercial transactions on favorable terms. For further information related to letter of credit agreements, the credit facilities, aspects of PG&E Corporation's accelerated share repurchase program and PG&E Corporation's guarantee related to certain NEGT indemnity obligations, see Notes 3, 6 and 12 of the Notes to the Consolidated Financial Statements. Amounts due

under these contracts are contingent upon terms contained in these agreements and are not included in the table of contractual commitments above.

PG&E Corporation and the Utility have significant contingencies that are discussed below and in Note 12 to the Notes to the Consolidated Financial Statements.

Various entities, including the Utility and the state of California are seeking up to $8.9 billion in refunds for electricity overcharges on behalf of California electricity purchasers for the period May 2000 to June 2001 through a proceeding pending at the FERC. This proceeding, the Refund Proceeding, commenced on August 2, 2000 when a complaint was filed against all suppliers in the ISO and PX markets. On July 25, 2001, the FERC held that refunds would be available for certain overcharges, and established a process to determine the refunds but asserted that it could not order market-wide refunds for periods before October 2, 2000. In December 2002, a FERC ALJ issued an initial decision in the Refund Proceeding finding that power suppliers overcharged the utilities, the state of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001, but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

In March 2003, the FERC confirmed most of the ALJ's findings in the Refund Proceeding, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. The FERC directed the ISO and the PX (which operates solely to reconcile remaining refund amounts owed) to make compliance filings establishing refund amounts. The ISO has indicated that it plans to make its compliance filing during the first half of 2005 with the PX to follow. In October 2003, the FERC affirmed its March 2003 decision and various parties appealed to the Ninth Circuit. Briefs have been submitted concerning which power suppliers are subject to refunds, the appropriate time period for which refunds can be ordered, and which transactions are subject to refunds. These matters will be argued before the Ninth Circuit on April 12 and 13, 2005, and a decision is expected in the following months.

The final refunds will not be determined until the FERC issues a final decision in the Refund Proceeding, following the ISO and PX compliance filings and the resolution of the appeals of the FERC's orders. In addition, future refunds could increase or decrease as a result of retroactive adjustments proposed by the ISO, which incorporate revised data provided by the Utility and other entities.

In the FERC's separate proceedings to investigate whether tariff violations occurred in the period before October 2, 2000, the FERC has asserted that it has the power to order power suppliers to disgorge any profits if the FERC finds that the tariffs in force at that time were violated or subject to manipulation. In September 2004, the Ninth Circuit found that the FERC has the authority to provide refunds for tariff violations involving inadequate transaction reporting for sales into the California spot markets throughout the period before October 2, 2000. The FERC has not yet acted on this finding and it is uncertain how it will be applied by the FERC.

The Utility recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as liabilities subject to compromise. This amount is subject to a pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. Under a bankruptcy court order, the aggregate allowable amount of ISO, PX and generator claims was limited to approximately $1.6 billion. The Utility currently estimates that the claims would have been reduced to approximately $1.0 billion based on the refund methodology recommended in the FERC ALJ's initial decision. The revised methodology adopted by the FERC's March 2003 decision could

further reduce the amount by several hundred million dollars, offset by the amount of any additional fuel cost allowance for suppliers.

The Utility has entered into settlements with various power suppliers resolving the Utility's claims against these power suppliers. As discussed in Note 1 of the Notes to the Consolidated Financial Statements, as of December 31, 2004, the Utility has recorded offsets to the Settlement Regulatory Asset of approximately $309 million, pre-tax ($183 million, after-tax) in connection with settlements. The final net after-tax amount of any amounts received by the Utility under future settlements with energy suppliers will be credited to customers, either as a reduction to the principal amount of the second series of ERBs, anticipated to be issued in November 2005, or if refunds are received after the second series of ERBs is issued, as a credit to the balancing account that tracks recovery of the customer costs and benefits related to the ERBs.

As discussed in Note 13 of the Notes to the Consolidated Financial Statements, in January 2005, the Utility and other parties entered into a settlement agreement with Mirant Corporation and its subsidiaries, to resolve Mirant's liability for FERC refunds, penalties and civil liabilities arising out of the California energy crisis. The settlement agreement is subject to approval by the FERC, the bankruptcy court overseeing Mirant's bankruptcy proceedings, and to the extent deemed necessary by the Utility, the bankruptcy court that retains jurisdiction over the Utility's Chapter 11 case. Although settlement discussions with a number of other major sellers and other market participants are continuing, the Utility cannot predict whether these settlement negotiations will be successful.

This section of MD&A discusses significant regulatory issues pending before the CPUC, the FERC, or the NRC, the resolution of which may affect the Utility's and PG&E Corporation's results of operations or financial condition.

The Utility's primary base revenue requirement proceeding is the general rate case filed with the CPUC. In the general rate case, the CPUC authorizes the amount the Utility can collect from customers to recover its basic business and operational costs for electricity and natural gas distribution and electricity generation operations. The general rate case typically sets the annual revenue requirement levels for a three-year rate period.

In May 2004, the CPUC issued a decision in the Utility's 2003 GRC. The decision approved the July 2003 and September 2003 settlement agreements reached among the Utility and various consumer groups to set the Utility's 2003 base revenue requirements at approximately:

As part of the GRC, the CPUC approved the following minimum and maximum yearly adjustments to the Utility's 2003 base revenue requirements, or attrition adjustments, for 2004, 2005, and 2006 based on the change in the CPI:

	2004	2005	2006
Electricity and Natural Gas Distribution
Minimum	2.00%	2.25%	3.00%
Multiplier	Change in CPI	Change in CPI	Change in CPI+1%
Maximum	3.00%	3.25%	4.00%
Electricity Generation
Minimum	1.50%	1.50%	2.50%
Multiplier	Change in CPI	Change in CPI	Change in CPI+1%
Maximum	3.00%	3.00%	4.00%

In addition, under the GRC decision, if the Utility forecasts a second refueling outage at Diablo Canyon in any one year, the electricity generation revenue requirement would be increased by $32 million per refueling outage, adjusted for changes in the CPI in the manner described in the decision. Currently, the only forecasted second refueling outage during the period 2004 to 2006 occurred in 2004.

As a result of the approval of the 2003 GRC, during the second quarter of 2004, the Utility recorded various regulatory assets and liabilities associated with revenue requirement increases, recovery of retained generation assets and unfunded taxes, depreciation, and decommissioning. During the third and fourth quarters of 2004, the Utility recorded electricity and natural gas distribution and electricity generation revenues under the new revenue requirements as approved by the 2003 GRC. The net increase in revenue requirements and revenues related to the 2003 GRC on the Utility's 2004 results of operations, on a pre-tax basis, is as follows:

		Revenue Requirement Increase
		Revenue Requirement Increase					Recognized in 2003		Recognized in 2004
		2003			2004		Recognized in 2003		Recognized in 2004
		(in millions)
Electricity revenue		$	273		$	277	$	268	$	282
Natural gas revenue			52			50		—		102
Electricity attrition			—			100		—		100
Natural gas attrition			—			19		—		19
Regulatory assets, net			(17	)		158		—		141

	Total	$	308		$	604	$	268	$	644

Because the Utility collected revenue subject to refund for electricity distribution and generation in 2003, but not for natural gas distribution, the impact of the 2003 GRC decision on the Utility's 2004 results of operations is different for each area.

For electricity distribution and generation, the Utility collected electricity revenue and surcharges subject to refund under the frozen rate structure in 2003. The amount of electricity revenue to be refunded in 2003 incorporated the impact of the electric portion of the GRC settlement, therefore this was recognized in net income in 2003. In 2004, the Utility recorded its electricity distribution and generation base revenue requirements under a cost-of-service ratemaking structure. Because the 2003 refund obligation already incorporated the impact of the GRC that related to fiscal 2003, the Utility recorded the increase related to 2004 in its 2004 results of operations of approximately $382 million, including attrition.

For natural gas distribution, since the CPUC issued a final decision on the Utility's 2003 GRC in 2004, the Utility recorded both the 2003 revenue requirement increase and the 2004 revenue requirement increase in its 2004 results of operations of approximately $121 million, including attrition.

In addition, as a result of the GRC decision, the Utility has recorded various regulatory assets and liabilities associated with the recovery of retained generation assets, unfunded taxes, depreciation, and decommissioning. The net impact of these items resulted in after-tax earnings of approximately $84 million recorded in the Utility's 2004 results of operations. These assets and liabilities are reflected in the Utility's current rates and will be amortized over their respective collection periods.

Another phase of the GRC was established to address the Utility's response to the December 2002 storm and the Utility's reliability performance. In October 2004, the CPUC voted to approve certain storm response improvement initiatives as well as a reliability performance incentive mechanism for the years 2005 through 2007. Under the performance incentive mechanism the Utility could receive up to $24 million each year depending on the extent to which the Utility exceeds the reliability performance

improvement targets, but could be required to pay a penalty of up to $24 million a year depending on the extent to which it fails to meet the targets. The decision does not provide the Utility with additional revenues to meet the reliability standards, but does include a margin of error around the targets in order to mitigate potential penalties. PG&E Corporation and the Utility are unable to predict whether or not the Utility will incur a reward or penalty related to the performance incentive mechanism.

In addition, on November 9, 2004, The Utility Reform Network, a consumer group, or TURN, filed a motion in the 2003 GRC seeking an investigation into the Utility's billing and collection practices alleging that the Utility's failure to issue timely bills and reliance on estimated billing constituted "billing errors" under the Utility's tariffs. In the case of "billing errors," the Utility is prohibited under its tariffs from billing customers for more than three months usage. The Utility responded to TURN's motion on December 30, 2004. On January 13, 2005, the CPUC adopted a resolution approving tariff changes stating that "billing error" includes failure to issue a bill and issuance of an estimated bill, under certain circumstances. The resolution stated that the tariff changes approved by the resolution "are consistent with existing CPUC policy, tariffs, and requirements." On February 17, 2005, the Utility filed an application for rehearing of this resolution with the CPUC on the basis that the resolution's characterization of the revised "billing error" definition as consistent with "existing CPUC policy, tariffs, and requirements," is contrary to both the plain language of the Utility's prior tariffs and the CPUC's own policies and requirements interpreting the Utility's prior tariffs. Although PG&E Corporation and the Utility are unable to predict whether TURN's motion for an investigation will be granted, PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse effect on PG&E Corporation's or the Utility's results of operations or financial condition.

The Utility's next GRC will be the 2007 GRC. The 2007 GRC will set the base revenue requirements for the years 2007 through 2009. The Utility plans to file its application for the 2007 GRC with the CPUC during the fourth quarter of 2005 with a final decision expected from the CPUC by the end of 2006. PG&E Corporation and the Utility are unable to predict what amount of revenue requirements the CPUC will authorize for the 2007 through 2009 period, when a final decision in this proceeding will be received, or the impact it will have on their financial condition or results of operations.

The CPUC determines the rate of return that the Utility may earn on its electricity and natural gas distribution, natural gas transmission and storage, and electricity generation assets. In December 2004, the CPUC issued a final decision approving a return on common equity, or ROE, for the Utility of 11.22% for 2004 and 2005, which is consistent with the Settlement Agreement. The Settlement Agreement provides that from January 1, 2004 until certain credit ratings are achieved, the Utility's authorized ROE will be no less than 11.22% per year. The Settlement Agreement also provides that the authorized equity ratio of the Utility's capital structure for ratemaking purposes will not be less than 52%, except that for 2004 and 2005 it may not be less than 48.6%. The decision authorizes the following cost of capital for 2004 and 2005:

	2004		2005
	Cost		Capital Structure		Weighted Cost		Cost		Capital Structure		Weighted Cost
Long-term debt	5.90	%	48.2	%	2.84	%	6.10	%	45.5	%	2.78	%
Preferred stock	6.76	%	2.8	%	0.19	%	6.42	%	2.5	%	0.16	%
Common equity	11.22	%	49.0	%	5.50	%	11.22	%	52.0	%	5.83	%
Return on rate base					8.53	%					8.77	%

The Utility's annual revenue requirement for 2004 decreased by approximately $105 million compared to the CPUC last authorized revenue requirement, as a result of interest savings associated with the Utility's Chapter 11 exit financing. This decision did not have an impact on the Utility's financial results for 2004 because the Utility has adjusted its operating revenues for the difference between its last authorized rate of return on rate base of 9.24% in 2003 and the lower rate of return on rate base of 8.53% in 2004 that has now been approved.

Effective January 1, 2003, as authorized by California law, the Utility established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the difference between the authorized revenue requirement and actual costs incurred under the Utility's authorized procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. The CPUC must review the revenues and costs associated with an investor-owned utility's electricity procurement plan at least semi-annually and adjust retail electricity rates or order refunds, as appropriate, when the forecast aggregate over-collections or under-collections exceed 5% of the utility's prior year electricity procurement revenues, excluding amounts collected for the DWR. The Utility's ERRA trigger threshold for 2004 is $191 million. As of December 31, 2004, the ERRA had an under-collected balance of approximately $75 million, which is below the 5% trigger for mandatory adjustment of rates. The CPUC approved an ERRA revenue requirement of $2.189 billion for 2004. In its 2005 ERRA application filed in June 2004, the Utility requested a forecast revenue requirement of $2.140 billion and the authority to amortize routine over and under-collections in the ERRA annually to coincide with January 1 rate changes. In December, 2004, the CPUC approved the Utility's Annual Electric True-up filing, under which the under-collections and over-collections in the Utility's electric-related balancing accounts, including the under-collection in the ERRA, are authorized to be recovered in the Utility's 2005 electric rates. A final decision on the 2005 ERRA application is expected in the first quarter of 2005.

The CPUC performs periodic compliance reviews of the procurement activities recorded in ERRA to ensure that the Utility's procurement activities are in compliance with its approved procurement plan. If the CPUC determines that the Utility's procurement activities were not in compliance with its approved procurement plan, some of the Utility's procurement costs could be disallowed. Procurement activities related to DWR allocated contracts could be disallowed up to a maximum of two times the Utility's administration costs associated with procurement, or $36 million for 2004. The Utility and the CPUC's Office of Ratepayer Advocates, or the ORA, have agreed that there should be no disallowances in the Utility's ERRA proceeding reviewing procurement activities during the period from January 1, 2003 through December 31, 2003, and have jointly recommended that the CPUC close the record period. PG&E Corporation and the Utility are unable to predict whether a disallowance will result or the size of any potential disallowance. In addition, it is uncertain whether the CPUC will modify or eliminate the maximum disallowance for future years.

As discussed in the "Overview" section above, in December 2004, the CPUC issued a final decision which approved, with certain modifications, each investor-owned electric utility's LTPP in order to authorize each utility to plan for and procure the resources necessary to provide reliable service to their customers for the ten-year period 2005-2014. The decision recognizes that each utility will have capacity needs over the ten-year period, especially in 2011 when most of the electricity

purchase contracts entered into by the DWR expire. In January 2005, several parties submitted applications for rehearing of the December 2004 CPUC decision. The Utility is unable to predict how or when the CPUC will respond to those applications.

In addition, the LTPP reflects that all California investor-owned electric utilities are required to achieve an electricity planning reserve margin of 15% to 17% in excess of peak capacity electricity requirements by June 1, 2006.

The CPUC may require the Utility, or the Utility may elect, to satisfy all or a part of the resources necessary to meet their customers' energy needs by developing or acquiring additional generation facilities or by entering into long-term power purchase agreements. The December 2004 CPUC decision requires the utilities to solicit bids from providers of all potential sources of new generation (e.g., conventional or renewable resources to be provided under utility owned projects or turnkey developments, or buyouts, or under third party power purchase agreements) through a single, open, transparent and competitive request for offers, or RFO, process, although a utility can tailor a RFO to meet specific resource needs. The CPUC requires the utilities to use an independent evaluator to review the RFO process. Before the CPUC decision was issued, the CPUC had approved the Utility's solicitation of offers for utility-owned generation development and for generation to be provided under long-term power purchase agreements for approximately 1,200 MW of peaking resources by 2008 and an additional 1,000 MW of load-following resources by 2010. The Utility issued two RFOs in November 2004 for these resources. In order to incorporate elements of the CPUC's December 2004 decision, the Utility notified bidders on January 7, 2005 that it was deferring its RFOs to evaluate how to incorporate new RFO requirements adopted by the CPUC. The Utility expects to issue updated RFOs in March 2005 and request initial bids to be submitted in April 2005. It is anticipated that contracts for the winning bidders would be submitted to the CPUC for approval in the second half of 2005. Completed projects could result in rate base additions in 2008.

To help assure recovery of the Utility's cost of new long-term resource commitments, the CPUC adopted a non-bypassable charge to be collected from all customers on whose behalf the Utility makes these new commitments, including those who subsequently receive generation from other load-serving entities.

In addition, in its decision approving the LTPP, the CPUC recognized that credit rating agencies will consider obligations under long-term procurement contracts to have debt-like characteristics that will adversely affect the Utility's credit ratios, which may, in turn, adversely affect the resulting credit ratings. The CPUC has agreed that it will consider the debt equivalence impact of procurement contracts on credit ratings in future cost of capital proceedings. The Utility is required to employ S&P's method for assessing the debt equivalence of power purchase agreements when evaluating bids in an all-source solicitation, except that the debt equivalence factor should be 20% instead of 30%. As the Utility enters into contracts with counterparties, the Utility will be exposed to the risk that counterparties will fail to perform and associated business credit risks.

The CPUC also determined that for utility-owned generation resources, the utilities are prohibited from recovering initial capital costs in excess of their final bid price. If final project costs are less than the final bid price, the savings would be shared with customers, while any cost overruns would be absorbed by the utilities. Costs of future plant additions and annual operating and maintenance costs and similar costs incurred by a utility would be eligible for cost-of service ratemaking treatment.

If the Utility is not able to recover a material part of the cost of developing or acquiring additional generation facilities in rates in a timely manner, PG&E Corporation's and the Utility's financial condition and results of operations would be materially adversely affected.

California law requires that, beginning in 2003, each California retail seller of electricity, except for municipal utilities, must increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year, the annual procurement target, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. In January 2005, the California Senate introduced a bill proposing to require the goal to be met by the end of 2010 instead of 2017. The CPUC also has suggested that the 20% goal be met by 2010. The Utility estimates that the accelerated goal would require the Utility to increase the amount of its annual renewable energy purchases to approximately 800-900 GWh. Based on the medium load scenario in the Utility's long-term electricity procurement plan, the Utility believes that it can meet the accelerated goal.

The Utility acts as a billing agent for the collection of the DWR's revenue requirements from the Utility's customers. The DWR's revenue requirements consist of a power charge to pay for the DWR's costs of purchasing electricity under its contracts and a bond charge to pay for the DWR's costs associated with its $11.3 billion bond offering completed in November 2002. In December 2004, the CPUC issued a decision on the permanent cost allocation methodology for the DWR's power charge revenue requirements in 2004 and subsequent years, among the three California investor-owned electric utilities. The Utility's customers' share of 2004 DWR power charge revenue requirement is approximately $1.7 billion after consideration of the DWR power charge adjustment to implement this decision. The Utility's customers' share of 2004 DWR bond charge revenue requirement is approximately $369 million. In January 2005, the CPUC granted limited rehearing of its permanent cost allocation decision to address how to calculate the above-market costs of the DWR power contracts. A final decision on DWR permanent cost allocation is expected in the first quarter of 2005. The Utility cannot predict the final outcome of this matter. As a result of the transition from frozen rates and the electricity procurement recovery mechanism described below, the collection of DWR revenue requirements, or any adjustments thereto, should not affect the Utility's results of operations.

On April 16, 2004, the Utility filed an updated Electric Restructuring Costs Account application for recovery of distribution related electric industry restructuring related revenue requirements totaling $117 million for the period 1999 through 2002. The Utility requested that the $117 million revenue requirement increase become effective January 1, 2005, and be recovered through future rates charged to customers. Revenue requirements associated with these ongoing activities in 2003 and afterwards are included in the 2003 GRC.

On December 2, 2004, the CPUC adopted a proposed settlement agreement to resolve issues in this proceeding filed by the Utility, ORA, Aglet Consumer Alliance, and TURN. Under the settlement agreement, the Utility is authorized to collect $80 million in revenue requirements to recover the distribution related electric industry restructuring costs through rates charged to certain of the Utility's customers beginning January 1, 2005. Additionally, beginning January 1, 2007, the Utility is required to remove from rate base all remaining net plant in service associated with the Utility's capital plant at issue in this application, projected to be approximately $30 million at the end of 2006. During the fourth quarter of 2004, the Utility recorded a net pre-tax regulatory asset of approximately $50 million, resulting in an increase of approximately $30 million in after-tax net income.

The Utility's electric transmission revenues and wholesale and retail transmission rates are subject to authorization by the FERC. In January and October 2003, the Utility filed applications with the FERC requesting authority to recover its annual electricity transmission retail revenue requirements for 2003 and 2004. During the third quarter of 2004, the FERC issued final orders on these applications, which did not have a material impact on the Utility's 2004 results of operations. The current approved rates will remain in effect until the Utility's next rate application. The Utility expects to file its next transmission owner rate case requesting approval of 2006 retail electric transmission revenue requirements in August 2005.

The Utility established a steam generated replacement project to replace turbines and steam generators and other equipment at the two nuclear operating units at the Diablo Canyon nuclear power plant. The Utility plans to replace Unit 2's steam generators in 2008 and replace Unit 1's steam generators in 2009. Because the fabrication of new steam generators requires a long lead-time, in August 2004 the Utility entered into contracts with Westinghouse Electric Company LLC, or Westinghouse, for the design, fabrication and delivery of eight steam generators. Under the contracts, the Utility must pay Westinghouse for all work done and pro-rated profit up to the time the contracts are completed or cancelled. The contracts require progress payments in line with actual expenditures for materials and work completed over the life of the contracts. The Utility is currently in negotiation for an installation contract for the new steam generators. The negotiation is expected to be completed by the end of February 2005. On January 25, 2005, a CPUC administrative law judge issued a proposed decision that would find the steam generator replacement project to be cost-effective and would authorize the Utility to recover the projected $706 million capital cost of the project in rates with no after-the-fact reasonableness review if the total costs do not exceed $706 million, and established a maximum project cost of $815 million. If the project costs exceed $706 million, or if the CPUC has reason to believe that the costs may be unreasonable regardless of the amount, the CPUC may conduct a reasonableness review of all costs. The proposed decision recommends that the Utility would be allowed to recover the revenue requirements related to the project in rates beginning on January 1 of the year following the commencement of commercial operations of each unit. The CPUC may act on the proposed decision at its meeting to be held on February 25, 2005. Assuming the CPUC approves the proposed decision, the Utility would make the capital expenditures required to maintain a 2008/2009 implementation schedule. It is expected that the CPUC will issue a final decision on whether to approve the project in September 2005, after considering the environmental impact review for the project. Expenditures on the project of approximately $25 million are expected to be incurred through February 2005 when the CPUC's decision on cost effectiveness is expected and these are expected to grow to approximately $70 million in September 2005 when the CPUC's final decision approving the project is expected. If the CPUC approves the project, the Utility estimates it would spend an additional $10 million in the last quarter of 2005. If the CPUC does not approve the projects, then the Utility will terminate the contracts and seek to recover the project costs that it incurred before termination from customers through the abandoned project process.

NRC granted authorization in March 2004 to build an on-site dry cask storage facility to store spent fuel through approximately 2021 for Unit 1 and to 2024 for Unit 2. However, several intervenors in that proceeding filed an appeal of the NRC's decision with the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. Oral arguments on that appeal are expected in the first quarter of 2005 with a decision anticipated in the second half of 2005. Construction of the on-site dry cask storage facility is expected to start in the second quarter of 2005 after grading permits are obtained from the County of San Luis Obispo. To provide another storage alternative in the event construction of the dry cask storage facility is delayed, the Utility has also requested that the NRC approve another storage option to install a temporary storage rack in each unit's existing spent fuel storage pool that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. If the Utility is unsuccessful in permitting and constructing the on-site dry cask storage facility, and is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2007 and until such time as additional spent fuel can be safely stored.

Annual Earnings Assessment Proceeding for Energy Efficiency Program Activities and Public Purpose Programs

In May 2004, 2003, 2002, 2001, and 2000, the Utility filed its annual applications with the CPUC claiming incentives totaling approximately $110 million for past energy efficiency and public purpose program activities. These applications remain subject to verification and approval by the CPUC. PG&E Corporation and the Utility are unable to predict the ultimate outcome of this proceeding.

In December 2004, the CPUC issued a final decision approving the Gas Accord III Settlement Agreement that sets the Utility's gas transmission and storage rates and market structure for a three-year term, commencing January 1, 2005. The decision extends the terms of a settlement agreement originally reached in 1997 called the Gas Accord. The CPUC has approved previous extensions of the Gas Accord. Under the terms of the recent decision, the Utility's revenue requirement has been set at $427.4 million for 2005, $435.5 million for 2006, and $443.7 million for 2007. This is compared to an authorized revenue requirement for 2004 of $416.9 million, adjusted for the CPUC's final decision in the cost of capital proceeding as discussed above. Under the Gas Accord, the Utility's gas transmission and storage facilities are operated on an open-access basis, thus allowing all eligible shippers to subscribe to gas transmission and storage services. In addition, the Utility assumes risk of not recovering its full natural gas transportation and storage costs since the Utility does not have a balancing account for over-collections or under-collections of natural gas transportation or storage revenues.

The original Gas Accord market structure included an incentive mechanism for recovery of core procurement costs, or the CPIM, which is used to determine the reasonableness of the Utility's costs of purchasing natural gas for its customers. Under the CPIM, costs that fall within a market-based tolerance band, which is currently 99% to 102% of the benchmark, are considered reasonable and fully recoverable in customers' rates. One-half of the costs above 102% of the benchmark are recoverable in the Utility's customers' rates, and the Utility's customers receive three-fourths of the savings when the costs are below 99% of the benchmark.

In 2004, the CPUC ordered the Utility and other California natural gas utilities to submit proposals addressing how California's long-term natural gas needs should be met through contracts with interstate pipelines, new liquefied natural gas facilities, storage facilities and in-state production of natural gas. Proposals were submitted in February 2004. The CPUC issued a decision in September 2004, which authorizes the utilities to expand their portfolios to access gas from multiple gas producing basins, to negotiate reduced capacity, and to terminate expiring contracts. The decision also established a pre-approval process for utility interstate and Canadian pipeline capacity contracts. The

second phase of this proceeding will establish a process to consider the adoption of standardized operational balancing agreements to connect all new upstream gas pipelines that interconnect with the pipeline systems of San Diego Gas and Electric and Southern California Gas Company.

The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations, financing arrangements, the marketplace for electricity, natural gas, electricity transmission, natural gas transportation and storage, other goods and services, and other aspects of their business. PG&E Corporation and the Utility categorize market risks as price risk, interest rate risk and credit risk. The Utility actively manages market risks through risk management programs that are designed to support business objectives, reduce costs, discourage unauthorized risk-taking, reduce earnings volatility and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. The Utility's risk management activities include the use of energy and financial instruments, including forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases.

The Utility estimates fair value of derivative instruments using the midpoint of quoted bid and asked forward prices, including quotes from customers, brokers, electronic exchanges and public indices, supplemented by online price information from news services. When market data is not available, the Utility uses models to estimate fair value.

PG&E Corporation currently has outstanding $280 million of 9.50% Convertible Subordinated Notes that are scheduled to mature on June 30, 2010. These Convertible Subordinated Notes may be converted (at the option of the holder) at any time prior to maturity into 18,558,655 shares of common stock of PG&E Corporation, at a conversion price of $15.09 per share. The conversion price is subject to adjustment should a significant change occur in the number of PG&E Corporation's outstanding common shares. To date, the conversion price has not required adjustment. In addition, the terms of the Convertible Subordinated Notes entitle the note holders to participate in any dividends declared and paid on PG&E Corporation's common shares based on their equity conversion value.

In accordance with SFAS No. 133. "Accounting for Derivative Instruments and Hedging Activities," or SFAS No. 133, the dividend participation rights component is considered to be an embedded derivative instrument and, therefore, must be bifurcated from the Convertible Subordinated Notes and marked to market on PG&E Corporation's Consolidated Statements of Operations as a non-operating expense (in Other expense, net), and reflected at fair value on PG&E Corporation's Consolidated Balance Sheets as $76 million of non-current liability (in Non-current liabilities—other) and $15 million of current liability (in Current liabilities—other). At December 31, 2004, the total estimated fair value of the dividend participation rights component on a pre-tax basis was approximately $91 million.

The Utility relies on electricity from a diverse mix of resources, including third-party contracts, amounts allocated under DWR contracts and its own electricity generation facilities. In addition, the Utility purchases and sells electricity on the spot market and the short-term forward market (contracts with delivery times ranging from one hour ahead to one year ahead).

It is estimated that the residual net open position (the amount of electricity needed to meet the demands of customers, plus applicable reserve margins, that is not satisfied from the Utility's own generation facilities, purchase contracts or DWR contracts allocated to the Utility's customers) will change over time for a number of reasons, including:

In addition, unexpected outages at the Utility's generation facilities, or a failure to perform by any of the counterparties to electricity purchase contracts or the DWR allocated contracts, would immediately increase the Utility's residual net open position. The Utility expects to satisfy at least some of the residual net open position through new contracts. In December 2004, the CPUC approved, with certain modifications, the Utility's LTPP for the 2005 through 2014 period. The LTPP is detailed in the preceding "Regulatory Matters" section of this MD&A.

The Settlement Agreement provides that the Utility will recover its reasonable costs of providing utility service, including power procurement costs. In addition, California law requires that the CPUC review revenues and expenses associated with a CPUC-approved procurement plan at least semi-annually through 2006 and adjust retail electricity rates, or order refunds when there is an under or over-collection exceeding 5% of the Utility's prior year electricity procurement revenues, excluding the revenue collected on behalf of the DWR. In addition, the CPUC has established a maximum procurement disallowance of approximately $36 million for the Utility's administration of the DWR contracts and least-cost dispatch. Adverse market price changes are not expected to impact the Utility's net income, while these cost recovery regulatory mechanisms remain in place. However, the Utility is at risk to the extent that the CPUC may in the future disallow transactions. Additionally, market price changes could impact the timing of the Utility's cash flows.

The Utility purchases nuclear fuel for Diablo Canyon through contracts with terms ranging from two to five years. These long-term nuclear fuel agreements are with large, well-established international producers in order to diversify its commitments and provide security of supply.

Nuclear fuel purchases are subject to tariffs of up to 8% on imports from certain countries. The Utility's nuclear fuel costs have not increased based on the imposed tariffs because the terms of the Utility's existing long-term contracts do not include these costs. However, these contracts expired at the end of 2004, and prices under new contracts may be higher as a result of such tariffs. In addition, because of an increase in U.S. demand for uranium compared with the domestic supply, uranium prices have been trending higher in 2005.

As the Utility replaces existing contracts ending in 2004, new higher priced uranium contracts will raise nuclear fuel costs. The Utility is expected to partially offset these higher prices by executing a portfolio of near- and long-term contracts for nuclear fuel components. These costs are recovered in

ERRA (see the "Electricity Resources" section of this MD&A); therefore, the changes in nuclear fuel prices are not expected to materially impact net income.

The Utility generally enters into physical and financial natural gas commodity contracts from one to 30 months in length to fulfill the needs of its retail core customers. Changes in temperature cause natural gas demand to vary daily, monthly and seasonally. Consequently, significant volumes of gas may be purchased in the monthly and, to a lesser extent, daily spot market. The Utility's cost of natural gas purchased for its core customers includes the commodity cost, the cost of Canadian and interstate transportation and gas storage costs.

Under the CPIM, the Utility's purchase costs for a twelve month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the benchmark, are considered reasonable and are fully recovered in customers' rates. One-half of the costs above 102% of the benchmark are recoverable in customers' rates, and the Utility's customers receive, in their rates, three-fourths of any savings resulting from the Utility's cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million. While this cost recovery mechanism remains in place, changes in the price of natural gas are not expected to materially impact net income.

The Utility currently faces price and volumetric risk for the portion of intrastate natural gas transportation capacity that is not contracted under fixed reservation charges used by core customers. Non-core customers contract with the Utility for natural gas transportation and storage, along with natural gas parking and lending (market center) services. The Utility is at risk for any natural gas transportation and storage revenue volatility. Transportation is sold at competitive market-based rates within a cost-of-service tariff framework. There are significant seasonal and annual variations in the demand for natural gas transportation and storage services. The Utility sells most of its pipeline capacity based on the volume of natural gas that is transported by its customers. As a result, the Utility's natural gas transportation revenues fluctuate.

The Utility uses value-at-risk to measure the expected maximum change over a one-day period in the 18-month forward value of its transportation and storage portfolio. This calculation is based on a 95% confidence level, which means that there is a 5% probability that the portfolio will incur a change in value in one day at least as large as the reported value-at-risk. For example, if the value-at-risk is calculated at $5 million, there is a 95% probability that if prices moved against current positions, the change in the value of the portfolio resulting from a one-day price movement would not exceed $5 million. The value-at-risk provides an indication of the Utility's exposure to potential market conditions that could impact revenues based on one-day price changes. It is also a way to measure the effectiveness of hedge strategies on a portfolio.

The Utility's value-at-risk for its transportation and storage portfolio was approximately $4 million at December 31, 2004 and approximately $4 million at December 31, 2003. A comparison of daily values-at-risk is included in order to provide context around the one-day amounts. The Utility's high, low and average transportation and storage value-at-risk during 2004 were approximately $6 million, $2 million and $4 million, respectively. The Utility's high, low and average transportation and storage value-at-risk during 2003 were approximately $13 million, $2 million and $5 million, respectively.

Value-at-risk has several limitations as a measure of portfolio risk, including, but not limited to, underestimation of the risk of a portfolio with significant options exposure, mismatch of one-day liquidation period assumed in the value-at-risk methodology as compared to the longer term holding

period of the storage and transportation portfolio, and inadequate indication of the exposure of a portfolio to extreme price movements. In addition, value-at-risk does not measure intra-day risk from position changes nor does it measure volumetric uncertainty in the demand for pipeline services.

Due to the limitations of value-at-risk, the Utility enhanced the calculation methodology during the fourth quarter of 2004 to 1) capture uncertainty with respect to demand (volumetric uncertainty) for pipeline services, 2) reflect the market conditions in which the pipeline operates by increasing the holding period to 12 months, and 3) include the uncertainty associated with the option exposure in the pipeline portfolio.

The calculation of value-at-risk under this methodology is based on a 99% confidence level, which means that there is a 1% probability that the portfolio will incur a change in value at least as large as the modified value-at-risk. This value-at-risk measure provides an indication of the Utility's exposure to potential market conditions that could impact revenues based on changes in market prices and demand for pipeline services over the 12-month holding period. The value-at-risk calculated under this methodology was approximately $35 million at December 31, 2004.

The Utility will calculate value-at-risk using the enhanced methodology on a prospective basis only, beginning January 1, 2005. For comparative purposes in 2005, the Utility will continue to report value-at-risk under the methodology formerly used in addition to value-at-risk calculated under the enhanced methodology.

Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cash flows. Specific interest rate risks for PG&E Corporation and the Utility include the risk of increasing interest rates on variable rate obligations.

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2004, if interest rates changed by 1% for all current variable rate debt held by PG&E Corporation and the Utility, the change would affect net income by an immaterial amount, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Credit risk is the risk of loss that PG&E Corporation and the Utility would incur if customers or counterparties failed to perform their contractual obligations.

PG&E Corporation had gross accounts receivable of approximately $2.2 billion at December 31, 2004 and approximately $2.5 billion at December 31, 2003. The majority of the accounts receivable were associated with the Utility's residential and small commercial customers. Based upon historical experience and evaluation of then-current factors, allowances for doubtful accounts of approximately $93 million at December 31, 2004 and approximately $68 million at December 31, 2003 were recorded against those accounts receivable. In accordance with tariffs, credit risk exposure is limited by requiring deposits from new customers and from those customers whose past payment practices are below standard. The Utility has a regional concentration of credit risk associated with its receivables from residential and small commercial customers in northern and central California. However, material loss due to non-performance from these customers is not considered likely.

The Utility manages credit risk for its wholesale customers and counterparties by assigning credit limits based on an evaluation of their financial condition, net worth, credit rating and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored frequently and a detailed credit analysis is performed at least annually.

Credit exposure for the Utility's wholesale customers and counterparties is calculated daily. If exposure exceeds the established limits, the Utility takes immediate action to reduce the exposure or obtain additional collateral, or both. Further, the Utility relies heavily on master agreements that require security, referred to as credit collateral, in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.

The Utility calculates gross credit exposure for each of its wholesale customers and counterparties as the current mark-to-market value of the contract (i.e., the amount that would be lost if the counterparty defaulted today), plus or minus any outstanding net receivables or payables, before the application of credit collateral. During 2004, the Utility recognized no material losses due to contract defaults or bankruptcies. At December 31, 2004, there were three counterparties that represented greater than 10% of the Utility's net wholesale credit exposure. Of these three counterparties, two were investment grade representing a total of approximately 47% of the Utility's net wholesale credit exposure and one was below investment grade representing approximately 17% of the Utility's net wholesale credit exposure.

The Utility conducts business with wholesale counterparties mainly in the energy industry, including other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, and oil and natural gas production companies located in the United States and Canada. This concentration of counterparties may impact the Utility's overall exposure to credit risk because counterparties may be similarly affected by economic or regulatory changes, or other changes in conditions. Credit losses experienced as a result of electrical and gas procurement activities are expected to be recoverable from customers and are therefore, not expected to have a material impact on earnings.

The preparation of Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies, due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ substantially from these estimates. These policies and their key characteristics are outlined below.

PG&E Corporation and the Utility account for the financial effects of regulation in accordance with SFAS No. 71. SFAS No. 71 applies to regulated entities whose rates are designed to recover the cost of providing service. SFAS No. 71 applies to all of the Utility's operations except for the operations of a natural gas pipeline. During the first quarter of 2004, the Utility began reapplying SFAS No. 71 to its generation operations.

Under SFAS No. 71, regulatory assets represent capitalized costs that otherwise would be charged to expense under GAAP. These costs are later recovered through regulated rates. Regulatory liabilities are created by rate actions of a regulator that will later be credited to customers through the ratemaking process. Regulatory assets and liabilities are recorded when it is probable, as defined in SFAS No. 5, "Accounting for Contingencies," or SFAS No. 5, that these items will be recovered or

reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, CPUC and FERC administrative law judge proposed decisions, final regulatory orders and the strength or status of applications for regulatory rehearings or state court appeals. The Utility also maintains regulatory balancing accounts, which are comprised of sales and cost balancing accounts. These balancing accounts are used to record the differences between revenues and costs that can be recovered through rates.

If the Utility determined that it could not apply SFAS No. 71 to its operations or, if under SFAS No. 71 it could not conclude that it is probable that revenues or costs would be recovered or reflected in future rates, the revenues or costs would be charged to income in the period in which they were incurred. If it is determined that a regulatory asset is no longer probable of recovery in rates, then SFAS No. 71 requires that it be written off at that time. At December 31, 2004, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of approximately $7.5 billion and regulatory liabilities (including current balancing accounts payable) of approximately $4.4 billion.

The Utility records revenue as electricity and natural gas are delivered. A portion of the revenue recognized has not yet been billed. Unbilled revenues are determined by factoring an estimate of the electricity and natural gas load delivered with recent historical usage and rate patterns. At December 31, 2004, the Utility had recorded approximately $550 million in unbilled revenues.

Given the complexities of the legal and regulatory environment regarding environmental laws, the process of estimating environmental remediation liabilities is a subjective one. The Utility records a liability associated with environmental remediation activities when it is determined that remediation is probable, as defined in SFAS No. 5, and the cost can be estimated in a reasonable manner. The liability can be based on many factors, including site investigations, remediation, operations, maintenance, monitoring and closure. This liability is recorded at the lower range of estimated costs, unless a more objective estimate can be achieved. The recorded liability is re-examined every quarter.

At December 31, 2004, the Utility's accrual for undiscounted environmental liability was approximately $327 million. The Utility's undiscounted future costs could increase to as much as $480 million if other potentially responsible parties are not able to contribute to the settlement of these costs or the extent of contamination or necessary remediation is greater than anticipated.

The accrual for undiscounted environmental liability is representative of future events that are likely to occur. In determining maximum undiscounted future costs, events that are possible but not likely are included in the estimation.

The Utility accounts for its nuclear generation and certain fossil generation facilities under SFAS No. 143, "Accounting for Asset Retirement Obligations," or SFAS No. 143. SFAS No. 143 requires that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and costs recovered through the ratemaking process.

There are uncertainties regarding the ultimate cost associated with retiring the assets the Utility has accounted for in accordance with SFAS No. 143. These include, but are not limited to changes in assumed dates of decommissioning, regulatory requirements, technology, cost of labor, materials, and equipment. At December 31, 2004, the Utility's estimated cost of retiring these assets is approximately $1.3 billion.

Certain employees and retirees of PG&E Corporation and its subsidiaries participate in qualified and non-qualified non-contributory defined benefit pension plans. Certain retired employees and their eligible dependents of PG&E Corporation and its subsidiaries also participate in contributory medical plans, and certain retired employees participate in life insurance plans (referred to collectively as other benefits). Amounts that PG&E Corporation and the Utility recognize as costs and obligations to provide pension benefits under SFAS No. 87, "Employers' Accounting for Pensions," and other benefits under SFAS No. 106, "Employers Accounting for Postretirement Benefits other than Pensions," are based on a variety of factors. These factors include the provisions of the plans, employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions utilized, PG&E Corporation's and the Utility's estimate of these costs and obligations is a critical accounting estimate.

Actuarial assumptions used in determining pension obligations include the discount rate, the average rate of future compensation increases and the expected return on plan assets. Actuarial assumptions used in determining other benefit obligations include the discount rate, the average rate of future compensation increases, the expected return on plan assets and the assumed health care cost trend rate. PG&E Corporation and the Utility review these assumptions on an annual basis and adjust them as necessary. While PG&E Corporation and the Utility believe the assumptions used are appropriate, significant differences in actual experience, plan changes or significant changes in assumptions may materially affect the recorded pension and other benefit obligations and future plan expenses.

In accordance with accounting rules, changes in benefit obligations associated with these assumptions may not be recognized as costs on the income statement. Differences between actuarial assumptions and actual plan results are deferred and are amortized into cost only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-value of the related plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. As such, significant portions of benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. PG&E Corporation's and the Utility's recorded pension expense totaled $182 million in 2004, $212 million in 2003 and $43 million in 2002, in accordance with the provisions of SFAS 87. PG&E Corporation's and the Utility's recorded expense for other postretirement and benefit obligations totaled $78 million in 2004, $76 million in 2003 and $50 million in 2002, in accordance with the provisions of SFAS 106. Under SFAS No. 71, regulatory adjustments have been recorded in the Consolidated Statements of Operations and Consolidated Balance Sheets of the Utility to reflect the difference between Utility pension expense or income for accounting purposes and Utility pension expense or income for ratemaking, which is based on a funding approach. The CPUC has authorized the Utility to recover the costs associated with its other benefits for 1993 and beyond. Recovery is based on the lesser of the amounts collected in rates or the annual contributions on a tax-deductible basis to the appropriate trusts.

PG&E Corporation's and the Utility's funding policy is to contribute tax deductible amounts, consistent with applicable regulatory decisions (including the 2003 GRC), sufficient to meet minimum funding requirements. Based upon current assumptions and available information, PG&E Corporation and the Utility have not identified any minimum funding requirements related to its pension plans, excluding amounts required to fund a voluntary retirement program of approximately $20 million

annually in 2005 and 2006. PG&E Corporation and the Utility have estimated funding requirements related to their postretirement benefit plans at approximately $65 million annually in 2005 and 2006. Contribution estimates for the Utility's pension and postretirement benefit plans after 2006 will be driven by future GRC decisions.

Pension and other benefit funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for pension and other benefit payments. Consistent with the trusts' investment policies, assets are invested in U.S. equities, non-U.S. equities and fixed income securities. Investment securities are exposed to various risks, including interest rate, credit and overall market volatility risks. As a result of these risks, it is reasonably possible that the market values of investment securities could increase or decrease in the near term. Increases or decreases in market values could materially affect the current value of the trusts and, as a result, the future level of pension and other benefit expense.

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit trusts, resulting in a weighted average rate of return on plan assets. Fixed income projected returns were based on historical returns for the broad U.S. bond market. Equity returns were based primarily on historical returns of the S&P 500 Index. For the Utility Retirement Plan, the assumed return of 8.1% compares to a ten-year actual return of 9.5%.

The rate used to discount pension and other post-retirement benefit plan liabilities was based on a yield curve developed from the Moody's AA Corporate Bond Index at December 31, 2004. This yield curve has discount rates that vary based on the maturity of the obligations. The estimated future cash flows for the pension and other post retirement obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions:

	Increase (decrease) in assumption		Increase in 2004 Pension Cost
	(in millions)
Discount rate	(0.5	)%	$	40	$	584
Rate of return on plan assets	(0.5	)%		32		—
Rate of increase in compensation	0.5	%		25		124

The following reflects the sensitivity of postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions:

	Increase (decrease) in assumption		Increase in 2004 Postretirement Benefit Cost
	(in millions)
Health care cost trend rate	0.5	%	$	5	$	37
Discount rate	(0.5	)%		2		84

In December 2004, the Financial Accounting Standards Board, or FASB, issued Statement No. 123 (revised December 2004), "Share-Based Payment," or SFAS No. 123R. SFAS No. 123R requires that the cost resulting from all share-based payment transactions be recognized in the financial statements and establishes a fair-value measurement objective in determining the value of such a cost. SFAS

No. 123R will be effective for the third quarter of 2005. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 123R on their Consolidated Financial Statements.

In December 2004, the FASB issued Statement No. 151, "Inventory Costs an amendment of ARB No. 43, Chapter 4", or SFAS No. 151. The guidance clarifies that the allocation of fixed production overhead to inventory is based on normal capacity. Abnormal amounts of idle facility, excess freight, handling costs and spoilage should be recognized as a current period charge. SFAS No. 151 will be effective January 1, 2006. The adoption of SFAS No. 151 is not expected to have a material effect on the financial position or results of operations of either PG&E Corporation or the Utility.

The IRS has completed its audit of PG&E Corporation's 1997 and 1998 consolidated federal income tax returns and has assessed additional federal income taxes of approximately $79 million (including interest). PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and currently is discussing these adjustments with the IRS' Appeals Office. PG&E Corporation does not expect final resolution of these appeals to have a material impact on its financial position or results of operations.

In the fourth quarter of 2003, PG&E Corporation made an advance payment to the IRS of $75 million relating to the 1999 and 2000 audit. The IRS completed its audit of PG&E Corporation's 1999 and 2000 consolidated federal income tax returns during the third quarter of 2004. As a result of the completion of this audit, PG&E Corporation received a refund from the IRS of $14 million in January of 2005.

The IRS is auditing PG&E Corporation's 2001 and 2002 consolidated federal income tax returns. In September 2004, the IRS issued notices of proposed adjustments that propose to disallow $104 million of synthetic fuel credits claimed on these tax returns. In addition, the IRS has proposed to disallow abandonment losses deducted on the 2002 tax return related to certain NEGT assets. These assets were transferred to NEGT lenders in the third quarter of 2004. In addition, the IRS has challenged other deductions related to NEGT prior to its Chapter 11 filing. PG&E Corporation is disputing the IRS's proposed adjustments and will contest these disallowances if the IRS continues to assert its current position.

PG&E Corporation has accrued $52 million associated with NEGT related tax liabilities. In addition, PG&E Corporation has accrued a $41 million liability to cover potential tax obligations relating to non-NEGT issues raised in outstanding tax audits. The Utility has accrued $62 million to cover potential tax obligations for outstanding tax audits. Considering these reserves, PG&E Corporation does not expect the resolution of these matters to have a material impact on its financial position or result of operations.

All IRS audits of PG&E Corporation's federal income tax returns prior to 1997 have been closed.

Prior to July 8, 2003, the date that NEGT filed for bankruptcy protection, PG&E Corporation recognized federal income tax benefits related to the losses of NEGT and its subsidiaries. However, after July 7, 2003, under the cost method of accounting PG&E Corporation has not recognized additional income tax benefits for financial reporting purposes with respect to the losses of NEGT and its subsidiaries even though it must continue to include NEGT and its subsidiaries in its consolidated income tax returns. After its equity ownership in NEGT was cancelled on the effective date of NEGT's plan of reorganization, PG&E Corporation no longer includes NEGT or its subsidiaries in its consolidated income tax returns. In addition, any remaining deferred tax assets related to NEGT or its subsidiaries, were reversed as discontinued operations in the Consolidated Statements of Operations at

the time PG&E Corporation's equity interest in NEGT was cancelled. See Note 5 of the Notes to the Consolidated Financial Statements for further discussion.

In addition to the reversal of deferred tax assets referred to above, and based on preliminary information provided by NEGT, PG&E Corporation anticipates paying approximately $86 million of consolidated federal tax obligations. This includes federal income taxes on NEGT activities through the effective date of NEGT's plan of reorganization.

PG&E Corporation and NEGT have entered into a separate agreement under which they have agreed to take certain actions and cooperate with each other with respect to certain tax matters, including future tax returns and audits.

For the year ended December 31, 2003, PG&E Corporation increased its valuation allowances against certain state deferred tax assets related to NEGT or its subsidiaries due to the uncertainty of their realization. During this period, valuation allowances of approximately $24 million were recorded in discontinued operations, and approximately $5 million was recorded in accumulated other comprehensive loss. No valuation allowances were recorded in the three-month period ended December 31, 2003 or during 2004.

At December 31, 2003, PG&E Corporation had $420 million of California net operating loss, or NOL. The California NOLs were fully utilized in 2004.

Various federal regulatory agencies have issued guidance and the NRC has issued orders regarding additional security measures to be taken at various facilities, including generation facilities, transmission substations and natural gas transportation facilities. The guidance and the orders require additional capital investment and increased operating costs. However, neither PG&E Corporation nor the Utility believes that these costs will have a material impact on its respective consolidated financial position or results of operations.

PG&E Corporation and the Utility are subject to laws and regulations established both to maintain and improve the quality of the environment. Where PG&E Corporation's and the Utility's properties contain hazardous substances, these laws and regulations may require PG&E Corporation and the Utility to remove those substances or to remedy effects on the environment. Also, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. See Note 12 of the Notes to the Consolidated Financial Statements for further discussion.

PG&E Corporation could be required to contribute capital to the Utility or be denied distributions from the Utility to the extent required by the CPUC's determination of the Utility's financial condition.

In approving the formation as the holding company of the Utility, the CPUC imposed certain conditions, including an obligation by PG&E Corporation's Board of Directors to give "first priority" to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve and to operate in a prudent and efficient manner. The CPUC later issued decisions in which it adopted an expansive interpretation of PG&E Corporation's obligations under this condition, including the requirement that PG&E Corporation, as well as each of the holding companies of the other major California investor-owned electric utilities, "infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve." PG&E Corporation and the other holding companies of the other major California investor-owned electric utilities appealed these decisions. On

May 21, 2004, the California Court of Appeal issued an opinion finding that the CPUC has limited jurisdiction over the holding companies to enforce the conditions imposed by the CPUC on their formations, but that the CPUC's decision interpreting the capital requirements condition was not ripe for review. On September 1, 2004, the California Supreme Court denied PG&E Corporation's petition seeking review of the California Court of Appeal's finding that the CPUC had limited jurisdiction.

Pursuant to the terms of the Settlement Agreement, the CPUC agreed that, once the CPUC approval of the Settlement Agreement is no longer subject to appeal, it will release all claims against PG&E Corporation and the Utility related to past holding company actions during the California energy crisis. Nevertheless, as now interpreted by the CPUC, whenever the Utility's financial health is impaired in the future, PG&E Corporation could be required to infuse the Utility with all types of capital necessary to fulfill its obligation to serve or to operate in a prudent and efficient manner. These obligations, if ultimately upheld by the courts, could materially restrict PG&E Corporation's ability to meet other obligations.

Adverse resolution of pending litigation could have a material adverse effect on PG&E Corporation's financial condition and results of operation.

PG&E Corporation has been named in lawsuits filed by the California Attorney General and the City and County of San Francisco, or CCSF, alleging unfair or fraudulent business acts or practices in violation of California Business and Professions Section 17200, or Section 17200, based on alleged violations of conditions established in the CPUC's holding company decisions caused by PG&E Corporation's alleged failure to provide adequate financial support to the Utility during the California energy crisis. The plaintiffs alleged that the transfer of money from the Utility to PG&E Corporation in the form of dividends and share repurchases violated Section 17200. These lawsuits have been consolidated and are pending in the San Francisco Superior Court, or Superior Court. The Attorney General and CCSF seek significant damages, penalties or equitable relief. On October 8, 2003, the U.S. District Court for the Northern District of California, or the District Court, held that the claims for damages were property of the Utility's bankruptcy estate, thus removing the damages claims from the lawsuits. The Attorney General and CCSF have appealed that decision to the U.S. Court of Appeals for the Ninth Circuit, or the Ninth Circuit, where it is currently pending. Oral argument on the appeal will be held on February 18, 2005. It is uncertain when a decision will be issued.

On January 21, 2005, the Superior Court issued a tentative ruling rejecting the standard advocated by the Attorney General and CCSF to calculate the number of violations that plaintiffs allege have been committed for purposes of determining the amount of potential civil penalties at issue. Under Section 17200, a penalty of up to $2,500 can be imposed for each violation. The Superior Court found that the appropriate standard was each transfer of money from the Utility to PG&E Corporation that plaintiffs allege violated Section 17200. Comments on the ruling are scheduled to be discussed at a case management conference to be held on February 25, 2005. PG&E Corporation believes that the plaintiffs' allegations are without merit. However, there can be no assurance that PG&E Corporation will prevail in these lawsuits.

If either or both of the CPUC's approval of the Settlement Agreement and the confirmation order are overturned or modified on appeal, PG&E Corporation's and the Utility's financial condition and results of operations could be materially adversely affected.

On December 18, 2003, the CPUC approved the Settlement Agreement and, on December 22, 2003, the bankruptcy court confirmed the Utility's plan of reorganization, which fully incorporates the Settlement Agreement as a material and integral part of the plan. On March 16, 2004, the CPUC denied applications that had been filed by several parties seeking rehearing of the CPUC's decision approving the Settlement Agreement. On April 15, 2004, two of these parties, CCSF and Aglet

Consumer Alliance, or Aglet, filed petitions for review of the CPUC's decisions with the California Court of Appeal. Three California state senators have filed a brief in support of the CCSF and Aglet petitions. The California Court of Appeal has not yet acted on the petitions.

In addition, appeals of the confirmation order were filed in the District Court by the two CPUC commissioners who did not vote to approve the Settlement Agreement, or the dissenting commissioners, and a municipality. On July 15, 2004, the District Court dismissed the appeals filed by the dissenting commissioners. The dissenting commissioners have appealed the District Court's order with the Ninth Circuit. The municipality's appeal remains pending at the District Court.

If the bankruptcy court's confirmation of the Utility's plan of reorganization or the Settlement Agreement is overturned or modified on appeal, PG&E Corporation's and the Utility's financial condition and results of operations, and the Utility's ability to pay dividends or otherwise make distributions to PG&E Corporation, could be materially adversely affected.

PG&E Corporation's and the Utility's financial viability depends upon the Utility's ability to recover its costs in a timely manner from the Utility's customers through regulated rates and otherwise execute its business strategy.

The Utility is a regulated entity subject to CPUC jurisdiction in almost all aspects of its business, including the rates, terms and conditions of its services, procurement of electricity and natural gas for its customers, issuance of securities, dispositions of utility assets and facilities and aspects of the siting and operation of its electricity and natural gas distribution systems. Executing the Utility's business strategy depends on periodic CPUC approvals of these and related matters. The Utility's ongoing financial viability depends on its ability to recover from its customers in a timely manner the Utility's costs, including the costs of electricity and natural gas purchased by it for its customers, in the Utility's CPUC-approved rates and its ability to pass through to its customers in rates the Utility's FERC-authorized revenue requirements.

The Utility's financial viability also depends on its ability to recover in rates an adequate return on its capital structure, including long-term debt and equity. During the California energy crisis, the high price the Utility had to pay for electricity on the wholesale market, coupled with its inability to fully recover its costs in retail rates, caused the Utility's costs to significantly exceed its revenues and ultimately caused the Utility to file a petition under Chapter 11. Even though the Settlement Agreement and current regulatory mechanisms contemplate that the CPUC will give the Utility the opportunity to recover its reasonable and prudent future costs in its rates, there can be no assurance that the CPUC will find that all of the Utility's costs are reasonable and prudent or will not otherwise take or fail to take actions to the Utility's detriment.

In addition, there can be no assurance that the bankruptcy court or other courts will implement and enforce the terms of the Settlement Agreement and the Utility's plan of reorganization in a manner that would produce the economic results that PG&E Corporation and the Utility intend or anticipate. Further, there can be no assurance that FERC-authorized tariffs will be adequate to cover the related costs. If the Utility is unable to recover any material amount of its costs through its rates in a timely manner, PG&E Corporation's and the Utility's financial condition and results of operations would be materially adversely affected.

The Utility may be unable to purchase electricity in the wholesale market or to increase its generating capacity in a manner that the CPUC will find reasonable or in amounts sufficient to satisfy the Utility's obligation to meet the electricity needs of its customers and the CPUC's electricity resource adequacy requirements.

The Utility's residual net open position (i.e., that portion of the Utility's electricity customers' demand not satisfied by electricity that the Utility generates or has under contract, or by electricity provided under the DWR allocated contracts) is expected to grow over time, as discussed in the "Risk

Management" section of this MD&A above. In addition, unexpected outages at the Utility's Diablo Canyon power plant or any of its other significant generation facilities, or a failure to perform by any of the counterparties to the Utility's electricity purchase contracts or the DWR allocated contracts, would immediately increase the Utility's residual net open position.

As existing electricity purchase contracts expire, sources of electricity otherwise become unavailable or demand increases, the Utility will purchase electricity in the wholesale market. These purchases will be made under contracts priced at the time of execution or, if made in the spot market, at the then-current market price of wholesale electricity. There can be no assurance that sufficient replacement electricity will be available at prices and on terms that the CPUC will find reasonable, or at all. The Utility's financial condition and results of operations would be materially adversely affected if it is unable to purchase electricity in the wholesale market at prices or on terms the CPUC finds reasonable or in quantities sufficient to satisfy the Utility's residual net open position.

California investor-owned electric utilities are required to achieve an electricity planning reserve margin of 15% to 17% in excess of peak capacity electricity requirements by June 1, 2006. In order to meet electricity resource adequacy requirements, the Utility may develop or acquire new generation facilities. The development or acquisition of additional generation facilities would require the Utility to incur significant additional capital expenditures or other costs and may require the Utility to issue additional debt, which it may not be able to issue on reasonable terms, or at all. The CPUC's December 16, 2004 decision approving the Utility's LTPP prohibits the Utility from recovering costs in excess of the Utility's projection of its initial capital costs included in the Utility's bid for Utility-owned generation. If the Utility is not able to recover a material part of the cost of developing or acquiring additional generation facilities in the Utility's rates in a timely manner, PG&E Corporation's and the Utility's financial condition and results of operations would be materially adversely affected.

The Utility's financial condition and results of operations could be materially adversely affected if it is unable to successfully manage the risks inherent in operating the Utility's facilities.

The Utility owns and operates extensive electricity and natural gas facilities that are interconnected to the U.S. western electricity grid and numerous interstate and continental natural gas pipelines. The operation of the Utility's facilities and the facilities of third parties on which it relies involves numerous risks, including:

The occurrence of any of these events could result in lower revenues or increased expenses, or both, that may not be fully recovered through insurance, rates or other means in a timely manner or at all.

Electricity and natural gas markets are highly volatile and insufficient regulatory responsiveness to that volatility could cause events similar to those that led to the filing of the Utility's Chapter 11 petition to occur.

In the recent past, the commodity markets for electricity and natural gas have been highly volatile and subject to substantial price fluctuations. A variety of factors may contribute to commodity market volatility, including:

These factors are largely outside the Utility's control. If wholesale electricity or natural gas prices increase significantly, public pressure or other regulatory or governmental influences or other factors could constrain the willingness or ability of the CPUC to authorize timely recovery of the Utility's costs. Moreover, the volatility of commodity markets could cause the Utility to apply more frequently to the CPUC for authority to timely recover its costs in rates. If the Utility is unable to recover any material amount of its costs in its rates in a timely manner, PG&E Corporation's and the Utility's financial condition and results of operations would be materially adversely affected.

The Utility's operations are subject to extensive environmental laws, and changes in, or liabilities under, these laws could adversely affect its financial condition and results of operations.

The Utility's operations are subject to extensive federal, state and local environmental laws. Complying with these environmental laws has in the past required significant expenditures for environmental compliance, monitoring and pollution control equipment, as well as for related fees and permits. Moreover, compliance in the future may require significant expenditures relating to electric and magnetic fields. The Utility also is subject to significant liabilities related to the investigation and remediation of environmental contamination at the Utility's current and former facilities, as well as at third-party owned sites. Due to the potential for imposition of stricter standards and greater regulation in the future and the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, conditions may change or additional contamination may be discovered, the Utility's environmental compliance and remediation costs could increase, and the timing of its capital expenditures in the future may accelerate. If the Utility is unable to recover the costs of complying with environmental laws in its rates in a timely manner, the Utility's financial condition and results of operations could be materially adversely affected. In addition, in the event the Utility must pay materially more than the amount that it currently has reserved on its balance sheet to satisfy its environmental remediation obligations and the Utility is unable to recover these costs from insurance or through rates in a timely manner, PG&E Corporation's and the Utility's financial condition and results of operations would be materially adversely affected.

The Utility faces the risk of unrecoverable costs if its customers obtain distribution and transportation services from other providers as a result of municipalization, competition, technological change, or other forms of bypass.

The Utility's customers could bypass its distribution and transportation system by obtaining service from other sources. Forms of bypass of the Utility's electricity distribution system include the construction of duplicate distribution facilities to serve specific existing or new customers, the municipalization of the Utility's distribution facilities by local governments or districts, and other forms of bypass or competition. Bypass of the Utility's system may result in stranded investment capital, loss of customer growth or additional barriers to cost recovery. Recently, both the Sacramento Municipal Utility District and South San Joaquin Irrigation District have studied the feasibility of condemning portions of the Utility's electric system within Yolo County and San Joaquin County, respectively. If these agencies continue their efforts, they must satisfy a number of legal steps, which will likely span several years. The Utility opposes these efforts as not being within the best interests of the customers within the subject areas, as well as other customers. The Utility's natural gas transportation facilities also are at risk of being bypassed by interstate pipeline companies that construct facilities in the Utility's markets or by customers who build pipeline connections that bypass the Utility's natural gas transportation and distribution system, or by customers who use and transport LNG. As customers and local public officials explore their energy options in light of the California energy crisis, these bypass risks may be increasing and may increase further if the Utility's rates exceed the cost of other available alternatives. In addition, technological changes could result in the development of economically attractive alternatives to purchasing electricity through the Utility's distribution facilities. Neither PG&E Corporation nor the Utility can currently predict the impact of these actions and developments on the Utility's business, although one possible outcome is a decline in the demand for the services that the Utility provides, which would result in a corresponding decline in the Utility's revenues and PG&E Corporation's consolidated revenues.

If the number of the Utility's customers declines due to municipalization, competition, technological changes or other forms of bypass, and the Utility's rates are not adjusted in a timely manner to allow it to fully recover its investment in electricity and natural gas facilities and electricity procurement costs, PG&E Corporation's and the Utility's financial condition and results of operations could be materially adversely affected.

The Utility faces the risk of unrecoverable costs resulting from changes in the number of customers in its service territory for whom the Utility purchases electricity.

As part of California's electricity industry restructuring, the Utility's customers were given the ability to choose to purchase electricity from alternate energy service providers and to thus become direct access customers. Customers who did not buy electricity from an alternate provider continued to receive electricity procurement, transmission and distribution services, or bundled service, from the Utility. Customers who chose an alternate electricity provider continued to receive transmission and distribution services from the Utility. The CPUC suspended the right of end-user customers to become direct access customers on September 20, 2001, although customers that were then direct access customers have been allowed to remain on direct access. During the 2003-2004 legislative session, the California legislature considered bills, including California Assembly Bill 428, or AB 428, which would have required the CPUC to establish rules for reintroduction of direct access through a phased implementation and to establish a model for direct access transactions. AB 428 would also have required the CPUC, for the period January 1, 2006 through January 1, 2009, to permit new direct access transactions in an amount equivalent to the combined amount of Statewide utility load growth and reduction in the electricity supply contract obligations of the DWR. While AB 428 was not approved by the legislature, there can be no assurance that a similar bill will not be introduced and approved in future legislative sessions.

Separately, the CPUC has instituted a rulemaking implementing California's Assembly Bill 117, which permits California cities and counties to purchase and sell electricity for their residents once they have registered as community choice aggregators. The Utility would continue to provide distribution, metering and billing services to the community choice aggregators' customers. Once registration has occurred, and the applicable community choice aggregator has received CPUC approval for its implementation plan, the community choice aggregator would purchase electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. The Utility would continue to be the electricity provider of last resort for all customers. If the Utility loses a material number of customers as a result of cities and counties electing to become community choice aggregators or the CPUC once again allows customers to migrate to direct access, the Utility's electricity purchase contracts could obligate it to purchase more electricity than the Utility's remaining customers require, the excess of which the Utility would have to sell, possibly at a loss. Further, if the Utility must provide electricity to customers discontinuing direct access or electing to leave a community choice aggregator, the Utility may be required to make unanticipated purchases of additional electricity at higher prices. If the Utility has excess electricity or it must make unplanned purchases of electricity as a result of changes in the number of community choice aggregators' customers or direct access customers and the CPUC fails to adjust the Utility's rates to reflect the impact of these actions, PG&E Corporation's and the Utility's financial condition and results of operations could be materially adversely affected.

The operation and decommissioning of the Utility's nuclear power plants expose it to potentially significant liabilities and capital expenditures.

The operation and decommissioning of the Utility's nuclear power plants expose it to potentially significant liabilities and capital expenditures, including those arising from the storage, handling and disposal of radioactive materials and uncertainties related to the regulatory, technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. The Utility maintains decommissioning trusts and external insurance coverage to reduce the Utility's financial exposure to these risks. However, the costs or damages the Utility may incur in connection with the operation and decommissioning of nuclear power plants could exceed the amount of the Utility's insurance coverage and other amounts set aside for these potential liabilities. In addition, as an operator of two operating nuclear reactor units, the Utility may be required under federal law to pay up to $201.2 million of liabilities arising out of each nuclear incident occurring not only at the Utility's Diablo Canyon power plant but at any other nuclear power plant in the United States.

In January 2004, the Utility filed an application with the CPUC seeking approval of projects to replace turbines and steam generators and other equipment at the two nuclear operating units at the Utility's Diablo Canyon nuclear power plant and authorization to recover the projected $706 million capital expenditures in rates. The Utility plans to replace Unit 2's steam generators in 2008 and to replace Unit 1's steam generators in 2009. On January 25, 2005, a CPUC administrative law judge issued a proposed decision that would find the steam generator replacement project to be cost-effective and would authorize the Utility to recover the projected $706 million capital cost of the project in rates with no after-the-fact reasonableness review if the total costs do not exceed $706 million, and established a maximum project cost of $815 million. If the project costs exceed $706 million, or if the CPUC has reason to believe that the costs may be unreasonable regardless of the amount, the CPUC may conduct a reasonableness review of all costs. The proposed decision recommends that the Utility would be allowed to recover the revenue requirements related to the project in rates beginning on January 1 of the year following the commencement of commercial operations of each unit. The CPUC may act on the proposed decision at its meeting to be held on February 25, 2005. Assuming the CPUC approves the proposed decision, the Utility would make the initial capital expenditures required to maintain a 2008/2009 implementation schedule. It is expected that the CPUC will issue a final decision, including incorporation of the environmental impact review for the projects, in September 2005. If the Utility cannot recover any material amount of these excess costs or damages in the Utility's rates in a

timely manner, PG&E Corporation's and the Utility's financial condition and results of operations would be materially adversely affected.

In addition, the NRC has broad authority under federal law to impose licensing and safety-related requirements upon owners and operators of nuclear power plants. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of the nuclear plant, or both, depending upon the NRC's assessment of the severity of the situation. Safety and security requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at the Utility's Diablo Canyon power plant and additional significant capital expenditures could be required in the future.

If the Utility fails to increase the spent fuel storage capacity at the Utility's Diablo Canyon power plant by the spring of 2007 and there are no other available spent fuel storage or disposal alternatives, the Utility would be forced to close this plant and would therefore be required to purchase electricity from more expensive sources.

Under the terms of the NRC operating licenses for the Utility's Diablo Canyon power plant, there must be sufficient storage capacity for the radioactive spent fuel produced by this plant. Under current operating procedures, the Utility believes that its Diablo Canyon power plant's existing spent fuel pools have sufficient capacity to enable it to operate until the spring of 2007. Although the Utility is taking actions to increase the Diablo Canyon power plant's spent fuel storage capacity and exploring other alternatives, there can be no assurance that the Utility can obtain the final necessary regulatory approvals to expand spent fuel capacity or that other alternatives will be available or implemented in time to avoid a disruption in production or shutdown of one or both units at this plant. As the proposed permanent spent fuel depository at Yucca Mountain, Nevada will not be available by 2007, there will not be any available third-party spent fuel storage facilities. If there is a disruption in production or shutdown of one or both units at this plant, the Utility will need to purchase electricity from more expensive sources.

Acts of terrorism could materially adversely affect PG&E Corporation's and the Utility's financial condition and results of operations.

The Utility's facilities, including its operating and retired nuclear facilities and the facilities of third parties on which we rely, could be targets of terrorist activities. A terrorist attack on these facilities could result in a full or partial disruption of the Utility's ability to generate, transmit, transport or distribute electricity or natural gas or cause environmental repercussions. Any operational disruption or environmental repercussions could result in a significant decrease in the Utility's revenues or significant reconstruction or remediation costs, which could materially adversely affect PG&E Corporation's and the Utility's financial condition and results of operations.

Adverse judgments or settlements in the chromium litigation cases could materially adversely affect PG&E Corporation's and the Utility's financial condition and results of operations.

The Utility is a named defendant in 14 civil actions currently pending in California courts relating to alleged chromium contamination. The chromium litigation complaints allege personal injuries, wrongful death and loss of consortium and seek unspecified compensatory and punitive damages based on claims arising from alleged exposure to chromium contamination in the vicinity of three of the Utility's natural gas compressor stations. If the Utility pays a material amount in excess of the amount that it currently has reserved on its balance sheet to satisfy chromium-related liabilities and costs, PG&E Corporation's and the Utility's financial condition and results of operations could be materially adversely affected.

The Utility's operations are subject to a number of federal and state statutes, CPUC and FERC regulations, rules and orders, as well as the terms of governmental permits, authorizations and licenses.

The Utility is obligated to comply in good faith with all applicable statues, rules, tariffs and orders of the CPUC, the FERC and the NRC relating to the aspects of its electricity and natural gas utility operations which fall within the jurisdictional authority of such regulatory agencies. These include customer billing, customer service, affiliate transactions, vegetation management, and safety and inspection practices. There is a risk that the interpretation and application of these statues, rules, tariffs and orders may change over time and that the Utility will be determined to have not complied with the new interpretation exposing the Utility to potential liability for customer refunds, penalties, or other amounts. As an example, the Utility is required to reimburse the California Department of Forestry, or CDF, for fire suppression costs when a fire on wild lands is caused by the Utility's failure to maintain a specified clearance between vegetation and overhead lines. Recently, the CDF has demanded the Utility pay for fire suppression costs regardless of whether the Utility is determined to be at fault in identifying and removing hazard trees.

Changes in, or liabilities under, the Utility's permits, authorizations or licenses could adversely affect PG&E Corporation's and the Utility's financial condition and results of operations.

The Utility is also required to comply with the terms of various permits, authorizations and licenses. These permits, authorizations and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. In connection with a license renewal, the FERC may impose new license conditions that could, among other things, require increased expenditures or result in reduced electricity output and/or capacity at the facility.

If the CPUC, the FERC, the NRC, or other regulatory agency having jurisdiction, makes a finding that the Utility did not comply with applicable rules, tariffs and orders, the Utility could be required to make customer refunds, pay penalties, or incur other non-recoverable expenses, which could have a material adverse effect on PG&E Corporation's and the Utility's financial condition and results of operations. Also, if the Utility is unable to obtain, renew or comply with these governmental permits, authorizations or licenses, or the Utility is unable to recover any increased costs of complying with additional license requirements or any other associated costs in its rates in a timely manner, PG&E Corporation's and the Utility's financial condition and results of operations could be materially adversely affected.

PG&E Corporation

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share amounts)

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

PG&E Corporation

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(in millions, except share amounts)

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions)

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(in millions, except share amounts)

As discussed further in Note 2, on April 12, 2004, the Utility's plan of reorganization under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, became effective, at which time the Utility emerged from Chapter 11.

Prior to October 29, 2004, the effective date of the plan of reorganization of National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., was the other significant subsidiary of PG&E Corporation. NEGT was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. On July 8, 2003, NEGT filed a voluntary petition for relief under Chapter 11. For the reasons described below in Note 5, PG&E Corporation considered NEGT to be an abandoned asset under Statement of Financial Accounting Standards, or SFAS, "Accounting for Impairment or Disposal of Long-Lived Assets," or SFAS No. 144, and, as a result, the operations of NEGT prior to July 8, 2003 and for all prior periods, are reflected as discontinued operations in the Consolidated Financial Statements. In addition, as discussed in Note 5, effective July 8, 2003, PG&E Corporation no longer consolidated the earnings and losses of NEGT or its subsidiaries and began accounting for its ownership interest in NEGT using the cost method, under which PG&E Corporation's investment in NEGT is reflected as a single amount within the December 31, 2003 Consolidated Balance Sheet of PG&E Corporation. On October 29, 2004, NEGT's plan of reorganization became effective and NEGT emerged from Chapter 11, at which time PG&E Corporation's equity interest in NEGT was cancelled.

This is a combined annual report of PG&E Corporation and the Utility. Therefore, the Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility's Consolidated Financial Statements include its accounts and those of its wholly owned and controlled subsidiaries and variable interest entities for which it is subject to a majority of the risk of loss or gain. All intercompany transactions have been eliminated from the Consolidated Financial Statements.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America, or GAAP, requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets and liabilities and the disclosure of contingencies and include, but are not limited to, estimates and assumptions used in determining the Utility's regulatory asset and liability balances based on probability assessments of regulatory recovery, revenues earned but not yet billed (including delayed billings), disputed claims, asset retirement obligations, allowance for doubtful accounts receivable, provisions for losses that are deemed probable from environmental remediation liabilities, pension liabilities, mark-to-market accounting under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, or SFAS No. 133, income tax related liabilities, litigation, and the Utility's review for impairment of long-lived assets and certain identifiable intangibles to be held and used whenever events or changes in circumstances indicate that the carrying amount of its assets might not

be recoverable. As these estimates and assumptions involve judgments on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict, actual results could differ from these estimates. PG&E Corporation's and the Utility's Consolidated Financial Statements reflect all adjustments that management believes are necessary for the fair presentation of their financial position and results of operations for the periods presented.

During the Utility's Chapter 11 proceeding, PG&E Corporation's and the Utility's Consolidated Financial Statements are presented in accordance with the American Institute of Certified Public Accountants' Statement of Position 90-7, "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code," or SOP 90-7. Under SOP 90-7, certain claims against the Utility existing before the Utility filed its Chapter 11 petition were classified as liabilities subject to compromise on PG&E Corporation's and the Utility's Consolidated Balance Sheets. Additionally, professional fees and expenses directly related to the Utility's Chapter 11 proceeding and interest income on funds accumulated during the Chapter 11 proceedings were reported separately as reorganization items.

The Utility discontinued the application of SOP 90-7 upon its emergence from Chapter 11 on April 12, 2004. The Consolidated Financial Statements as of and for the years ending December 31, 2003 and 2002, have been presented in accordance with SOP 90-7. Although the Utility emerged from Chapter 11 on April 12, 2004, the bankruptcy court retained jurisdiction, among other things, to resolve disputed claims made in the Chapter 11 case. Upon the effective date of the Utility's plan of reorganization, $1.8 billion was deposited into escrow, pending the resolution of disputed claims, and has been classified as restricted cash in current assets on PG&E Corporation's and the Utility's December 31, 2004 Consolidated Balance Sheets. The related remaining pre-petition disputed claims are subject to resolution by the bankruptcy court and are classified as current liabilities on the Consolidated Balance Sheets at December 31, 2004.

Certain amounts in the 2003 and 2002 Consolidated Financial Statements and Notes to the Consolidated Financial Statements have been reclassified to conform to the 2004 presentation. These reclassifications did not affect the consolidated net income of PG&E Corporation and the Utility for the periods presented, nor did they impact revenues, operating income, current assets or liabilities, or total assets or equity.

Earnings (loss) per share is calculated utilizing the "two-class" method by dividing earnings (loss) allocated to common shareholders by the weighted average number of common shares outstanding during the period.

The following is a reconciliation of PG&E Corporation's net income (loss) and weighted average common shares outstanding for calculating basic and diluted net income (loss) per share:

On March 31, 2004, the Financial Accounting Standards Board, or FASB, ratified the consensus reached by the Emerging Issues Task Force, or the EITF, on EITF Issue 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. 128," or EITF 03-06. EITF 03-06 provides additional guidance related to the calculation of earnings per share under SFAS No. 128, "Earnings per Share," or SFAS No. 128, which includes application of the "two-class" method in computing earnings

per share, identification of participating securities, and requirements for the allocation of undistributed earnings (and losses) to participating securities.

PG&E Corporation currently has outstanding $280 million of 9.50% Convertible Subordinated Notes due 2010, or Convertible Subordinated Notes, that are entitled to receive (non-cumulative) dividend payments without exercising the conversion option. These Convertible Subordinated Notes meet the criteria of a participating security in the calculation of basic earnings per share using the "two-class" method of SFAS No. 128. Therefore, EITF 03-06 requires that earnings be allocated between common stock and the participating security. PG&E Corporation adopted EITF 03-06 in the first quarter of 2004 and for all subsequent and all prior periods presented.

In applying the "two-class" method, the following reflects the earnings (loss) allocated to common shareholders after the inclusion of participation rights related to PG&E Corporation's Convertible Subordinated Notes in the allocation of earnings. The Convertible Subordinated Notes are convertible at the option of the holders into 18,558,655 common shares. All PG&E Corporation's participating securities participate on a 1:1 basis in dividends with common shareholders.

	2004		2003			2002
Earnings (loss) allocated to common shareholders, basic
Income from continuing operations	$	3,646	$	754		$	1,682
Discontinued operations		653		(348	)		(2,476	)
Cumulative effect of changes in accounting principles		—		(6	)		(60	)
Rounding		—		—			1

	$	4,299	$	400		$	(853	)

Earnings (loss) allocated to common shareholders, diluted
Income from continuing operations	$	3,650	$	755		$	1,683
Discontinued operations		653		(348	)		(2,476	)
Cumulative effect of changes in accounting principles		—		(6	)		(60	)

	$	4,303	$	401		$	(853	)

Options to purchase PG&E Corporation common shares of 7,046,710 in 2004, 16,008,087 in 2003 and 21,150,557 in 2002 were outstanding, but not included in the computation of diluted earnings per share because the option exercise prices were greater than the average market price.

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

Adoption of New Accounting Policies and Summary of Significant Accounting Policies

The accounting policies used by PG&E Corporation and the Utility include those necessary for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utilities Commission, or the CPUC, or the Federal Energy Regulatory Commission, or the FERC.

Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003

In May 2004, FASB issued Staff Position SFAS No. 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," or FSP 106-2. FSP 106-2 supersedes FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," and provides guidance on the accounting, disclosure, effective date, and transition requirements related to the Medicare Prescription Drug Act. FSP 106-2 was effective for the third quarter of 2004. The

adoption of FSP 106-2 did not have any impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

The U.S. Department of Health and Human Services issued the final regulations on prescription drug benefits on January 21, 2005. Despite the initial preliminary conclusion that the Utility's postretirement medical plan, or the Plan, did not qualify for the federal subsidy, the final regulations may allow the Plan to qualify for the federal subsidy. PG&E Corporation and the Utility are continuing to evaluate the effects, if any, of the final regulations on the Plan, and the impact on the Consolidated Financial Statements.

In December 2003, FASB issued Interpretation No. 46 (revised December 2003), "Consolidation of Variable Interest Entities," or FIN 46R. FIN 46R provides that an entity is a variable interest entity, or VIE, if it does not have sufficient equity investment at risk, or if the holders of the entity's equity instruments lack the essential characteristics of a controlling financial interest. FIN 46R requires that the company that is subject to a majority of the risk of loss from a VIE's activities, or is entitled to receive a majority of the entity's residual returns, or both, consolidate the VIE. A company that consolidates a VIE is called the primary beneficiary.

PG&E Corporation and the Utility adopted FIN 46R on January 1, 2004. The adoption of FIN 46R did not have any impact on net income.

The Utility invests in low-income housing partnerships, or LIHPs. The entities were formed to invest in low-income housing projects sponsored by non-profit organizations in the state of California. The Utility determined that it was the primary beneficiary of one LIHP, resulting in its consolidation, and an increase in total assets and total liabilities of $12 million in PG&E Corporation's and the Utility's Consolidated Balance Sheets. The consolidated LIHP has issued debt in the amount of $5 million, which is secured by assets of the partnership, totaling $26 million, and the Utility's commitment to make capital infusions of approximately $11 million over the next five years.

The Utility is not considered to be the primary beneficiary of any other LIHPs. The maximum exposure to loss from its investment in unconsolidated LIHPs is the Utility's investment of $5 million at December 31, 2004.

The nature of power purchase agreements is such that the Utility could have a significant variable interest in a power purchase agreement counterparty if that entity is a VIE owning one plant that sells substantially all of its output to the Utility, and the contract price for power is correlated with the plant's variable costs of production. The Utility determined that none of its current power purchase agreements represent significant variable interests. The EITF continues to review how companies determine whether an arrangement is a variable interest. Their findings could impact how the determination is applied to the Utility's power purchase agreements in the future.

In November 2003, the FASB approved an amendment to an interpretation issued by the Derivatives Implementation Group, C15, or DIG C15, as previously amended in October 2001 and December 2001, that changed the definition of normal purchases and sales for certain power contracts that contain option-like features.

PG&E Corporation and the Utility had previously adopted the new DIG C15 guidelines prospectively for new derivative instruments entered into after June 30, 2003. On January 1, 2004, PG&E Corporation and the Utility adopted the new DIG C15 guidelines for certain power contracts that contain option-like features that existed prior to July 1, 2003. The adoption of DIG C15 did not have any impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

PG&E Corporation and the Utility account for the financial effects of regulation in accordance with "Accounting for the Effects of Certain Types of Regulation," as amended, or SFAS No. 71. SFAS No. 71 applies to regulated entities whose rates are designed to recover the costs of providing service. The Utility is regulated by the CPUC, the FERC and the Nuclear Regulatory Commission, or the NRC, among others. As discussed further in Note 2, during the first quarter of 2004, the Utility began reapplying SFAS No. 71 to its generation operations. As a result, as of March 31, 2004, the Utility recorded a generation regulatory asset of approximately $1.2 billion. SFAS No. 71 now applies to all of the Utility's operations except for the operations of a natural gas pipeline.

SFAS No. 71 provides for recording regulatory assets and liabilities when certain conditions are met. Regulatory assets represent the capitalization of incurred costs that would otherwise be charged to expense when it is probable that the incurred costs will be included for ratemaking purposes in the future. Regulatory liabilities represent rate actions of a regulator that will result in amounts that are to be credited to customers through the ratemaking process.

To the extent that portions of the Utility's operations cease to be subject to SFAS No. 71 or recovery is no longer probable as a result of changes in regulation or the Utility's competitive position, the related regulatory assets and liabilities are written off.

Accounting for Financial Instruments with Characteristics of Both Liabilities and Equity

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

PG&E Corporation and the Utility adopted the requirements of SFAS No. 150 in the third quarter of 2003. As a result, the Utility reclassified approximately $137 million of preferred stock with mandatory redemption provisions as a noncurrent liability. The reclassification did not have an impact on earnings of PG&E Corporation or the Utility. Upon adopting SFAS No. 150, all amounts paid or to be paid to the holders of preferred stock with mandatory redemption provisions in excess of the initial measured amount are reflected in interest expense. Dividends paid or accrued in prior periods have not been reclassified.

On January 1, 2003, PG&E Corporation and the Utility adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," or SFAS No. 143. The Utility identified its nuclear generation and certain fossil fuel generation facilities as having asset retirement obligations under SFAS No. 143. SFAS No. 143 requires that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the long-lived asset. Rate-regulated entities may recognize regulatory assets or

liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and costs recovered through the ratemaking process. The cumulative effect of the change in accounting principle for the Utility's fossil fuel facilities as a result of adopting SFAS No. 143 was a loss of approximately $1 million, after-tax.

The Utility has established trust funds that are legally restricted for purposes of settling its nuclear decommissioning obligations. The fair value and carrying value of these trust funds was approximately $1.6 billion at December 31, 2004 and approximately $1.5 billion at December 31, 2003.

The Utility may have potential asset retirement obligations under various land right documents associated with its transmission and distribution facilities. The majority of the Utility's land rights are perpetual. Any non-perpetual land rights generally are renewed continuously because the Utility intends to utilize these facilities indefinitely. Since the timing and extent of any potential asset retirements are unknown, the fair value of any obligations associated with these facilities cannot be reasonably estimated.

The Utility collects estimated removal costs in rates through depreciation in accordance with regulatory treatment. These amounts do not represent SFAS No. 143 asset retirement obligations. Historically, these removal costs have been recorded in accumulated depreciation. However, as a result of guidance from the staff of the Securities and Exchange Commission, or SEC, the Utility reclassified this obligation to a regulatory liability in its 2003 and 2002 Consolidated Balance Sheet during 2003. The Utility's estimated removal costs recorded as a regulatory liability were approximately $2.0 billion at December 31, 2004 and approximately $1.8 billion at December 31, 2003.

PG&E Corporation and the Utility had no goodwill on their Consolidated Balance Sheets at December 31, 2004 or 2003. Other intangible assets consist mainly of hydroelectric facility licenses and other agreements, with lives ranging from 17 to 40 years. The gross carrying amount of the hydroelectric facility licenses and other agreements was approximately $73 million at December 31, 2004 and December 31, 2003. The accumulated amortization was approximately $23 million at December 31, 2004 and $19 million at December 31, 2003.

The Utility's amortization expense related to intangible assets was approximately $4 million in 2004, $3 million in 2003 and $3 million in 2002. The estimated annual amortization expense based on the December 31, 2004 intangible asset balance for the Utility's intangible assets for 2005 through 2009 is approximately $4 million each year.

Invested cash and other investments with original maturities of three months or less are considered cash equivalents. Cash equivalents are stated at cost, which approximates fair value. PG&E Corporation and the Utility primarily invest their cash in money market funds and in short-term obligations of the U.S. government and its agencies.

The Utility had account balances with Citigroup Asset Management and Janus Capital Group that were greater than 10% of PG&E Corporation's and the Utility's total cash and cash equivalents balance at December 31, 2004.

Restricted cash includes Utility amounts held in escrow as required by the bankruptcy court related to remaining disputed claims and as collateral while in Chapter 11, as required by the California Independent System Operator, or ISO, the State of California and other counterparties. The Utility

also provides deposits to counterparties in the normal course of operations and under certain third party agreements.

Inventories include materials, supplies and gas stored underground and are valued at average cost. Materials and supplies are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Materials provisions are made for obsolete inventory. Gas stored underground is charged to inventory when purchased and then expensed upon distribution.

PG&E Corporation and the Utility use the liability method of accounting for income taxes. Income tax expense (benefit) includes current and deferred income taxes resulting from operations during the year. Investment tax credits are amortized over the life of the related property. Other tax credits, mainly synthetic fuel tax credits, are recognized in income as earned.

PG&E Corporation files a consolidated U.S. (federal) income tax return that includes domestic subsidiaries in which its ownership is 80% or more. In addition, PG&E Corporation files combined state income tax returns where applicable. PG&E Corporation and the Utility are parties to a tax-sharing arrangement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.

Prior to July 8, 2003, the date of NEGT's Chapter 11 filing, PG&E Corporation recognized federal income tax benefits related to the losses of NEGT and its subsidiaries. However, after July 7, 2003, under the cost method of accounting PG&E Corporation has not recognized additional income tax benefits for financial reporting purposes with respect to the losses of NEGT and its subsidiaries. PG&E Corporation is required to continue to include NEGT and its subsidiaries in its consolidated income tax returns covering all periods through October 29, 2004, the effective date of NEGT's plan of reorganization and the cancellation of its equity ownership in NEGT. See Note 11 for further discussion.

The Utility has investments in unconsolidated affiliates, which are mainly engaged in the purchase of low-income residential real estate property. The equity method of accounting is applied to the Utility's investment in these entities. Under the equity method, the Utility's share of equity income or losses of these entities is reflected as equity in earnings of affiliates. As of December 31, 2004, the Utility's recorded investment in these entities totaled approximately $5 million in accordance with the equity method of accounting. As a limited partner, the Utility's exposure to potential loss is limited to its investment in each partnership.

In accordance with various agreements, the Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. These services are priced either at the fully loaded cost (i.e., direct costs and allocations of overhead costs) or at the higher of fully loaded cost or fair market value, depending on the nature of the services. PG&E Corporation also allocates certain other corporate administrative and general costs to the Utility and other subsidiaries using agreed allocation factors, including the number of employees, operating expenses excluding fuel purchases, total assets and other cost allocation methodologies. The Utility purchases natural gas transportation services from Gas Transmission Northwest Corporation, or GTNW, formerly known as PG&E Gas Transmission, Northwest Corporation. Effective April 1, 2003, the Utility

no longer purchases natural gas from NEGT Energy Trading Holdings Corporation, or NEGT ET, formerly known as PG&E Energy Trading Holdings Corporation. Both GTNW and NEGT ET are no longer related parties after the cancellation of PG&E Corporation's equity interest in NEGT on the effective date of its plan of reorganization, October 29, 2004. The Utility sold natural gas transportation capacity and other ancillary services to NEGT ET until NEGT's Chapter 11 proceeding was imminent. These services were priced at either tariff rates or fair market value, depending on the nature of the services provided. Through July 7, 2003, all significant intercompany transactions with NEGT and its subsidiaries were eliminated in consolidation; therefore, no profit or loss resulted from these transactions. Beginning July 8, 2003, the Utility's transactions with NEGT are no longer eliminated in consolidation. The Utility's significant related party transactions and related receivable (payable) balances were as follows:

As discussed further in Note 2, as of March 31, 2004, PG&E Corporation recorded the impact of the settlement agreement, entered into on December 19, 2003, among PG&E Corporation, the Utility and the CPUC to resolve the Utility's Chapter 11 case, or the Settlement Agreement. The Settlement Agreement precluded the Utility from reimbursing PG&E Corporation for certain Chapter 11 related costs. As such, PG&E Corporation reduced its receivable from the Utility, and the Utility reduced its payable to PG&E Corporation by $129 million. The transactions were recorded as a contribution of equity to the Utility by PG&E Corporation, net of taxes of $52 million, and an increase to additional-paid-in-capital by the Utility in the first quarter of 2004.

Property, plant and equipment are reported at their original costs. Original costs include:

As discussed in Note 3, substantially all of the Utility's real property and certain tangible personal property related to the Utility's facilities serve as collateral for the first mortgage bonds, or First Mortgage Bonds.

Capitalized Interest and AFUDC—AFUDC is the estimated cost of debt and equity funds used to finance regulated plant additions that is allowed to be recorded as part of the costs of construction projects. AFUDC is recoverable from customers through rates once the property is placed in service. The Utility had capitalized interest and AFUDC of approximately $32 million at December 31, 2004 and $29 million at December 31, 2003. PG&E Corporation on a stand-alone basis did not have any capitalized interest and AFUDC at December 31, 2004 and 2003.

Depreciation—The Utility's composite depreciation rate was 3.42% in 2004, 2003 and 2002.

		Gross Plant		Estimated useful lives
		(in millions)
Electricity generating facilities		$	1,885	15 to 50 years
Electricity distribution facilities			13,962	16 to 58 years
Electricity transmission			3,644	40 to 70 years
Natural gas distribution facilities			4,634	23 to 54 years
Natural gas transportation			2,828	25 to 45 years
Natural gas storage			47	25 to 48 years
Other			3,045	5 to 40 years

	Total	$	30,045

The useful lives of the Utility's property, plant and equipment are authorized by the CPUC and the FERC and depreciation expense is included within the recoverable costs of service included in rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated future removal costs, net of any salvage value at retirement. The Utility has a separate rate component for the accrual of its recorded obligation for nuclear decommissioning, which is included in depreciation, amortization and decommissioning expense in the accompanying Consolidated Statements of Operations.

PG&E Corporation and the Utility charge the original cost of retired plant and removal costs less salvage value to accumulated depreciation upon retirement of plant in service for the Utility's lines of business that apply SFAS No. 71, which include electricity and natural gas distribution, electricity generation and transmission, and natural gas transportation and storage. PG&E Corporation and the Utility expense repair and maintenance costs as incurred.

Nuclear Fuel—Property, plant and equipment also includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted average cost. Nuclear fuel in the reactor is amortized based on the amount of energy output.

Capitalized Software Costs—PG&E Corporation and the Utility capitalize costs incurred during the application development stage of internal use software projects to property, plant and equipment. Capitalized software costs totaled $231 million at December 31, 2004 and $273 million at December 31, 2003, net of accumulated amortization of approximately $196 million at December 31, 2004 and $159 million at December 31, 2003. PG&E Corporation and the Utility amortize capitalized software costs ratably over the expected lives of the projects ranging from 3 to 15 years, commencing upon operational use, in accordance with regulatory recovery requirements.

The carrying values of long-lived assets are evaluated in accordance with the provisions of SFAS No. 144. In accordance with SFAS No. 144, PG&E Corporation and the Utility evaluate the carrying amounts of long-lived assets for impairment whenever events occur or circumstances change that may affect the recoverability or the estimated life of long-lived assets. SFAS No. 144 became effective at the beginning of 2002 and supersedes SFAS No. 121, "Accounting for the Impairment or Disposal of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," and the accounting and reporting provisions of Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations for a Disposal of a Segment of a Business." The adoption of SFAS No. 144 did not have a material impact on the consolidated financial position, results of operations or cash flows of PG&E Corporation or the Utility. During 2003 and 2002, NEGT recorded certain impairment charges in accordance with SFAS No. 144. See Note 5 for further discussion.

Gains and losses on debt extinguishments associated with regulated operations that are subject to the provisions of SFAS No. 71 are deferred and amortized over the remaining original amortization period of the debt reacquired, consistent with recovery of costs through regulated rates. Gains and losses on debt extinguishments associated with unregulated operations are recognized at the time such debt is reacquired and are reported as interest expense.

The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced 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 and the Utility use the following methods and assumptions in estimating fair value disclosures for financial instruments:

The carrying amount and fair value of PG&E Corporation's and the Utility's financial instruments are as follows (the table below excludes financial instruments with fair values that approximate their carrying values, as these instruments are presented in the Consolidated Balance Sheets):

		Balance at December 31,
		2004		2003
		(in millions)
Settlement Regulatory Asset		$	3,188	$	—
Utility retained generation regulatory assets			1,181		—
Rate reduction bond assets			741		1,054
Regulatory assets for deferred income tax			490		324
Unamortized loss, net of gain, on reacquired debt			345		277
Environmental compliance costs			192		139
Post-transition period contract termination costs			142		151
Regulatory assets associated with plan of reorganization			182		—
Other, net			65		56

	Total regulatory assets	$	6,526	$	2,001

Amortization of regulatory assets are charged to expense during the period that the costs are reflected in regulated revenues. In light of the satisfaction of various conditions to the implementation of the plan of reorganization, the accounting probability standard required to be met under SFAS No. 71 in order for the Utility to recognize the regulatory assets provided under the Settlement Agreement (as described in Note 2) was met as of March 31, 2004. Therefore, the Utility recorded the $3.7 billion, pre-tax ($2.2 billion, after-tax), regulatory asset established under the Settlement Agreement, or the Settlement Regulatory Asset, and $1.2 billion, pre-tax ($0.7 billion, after-tax), for the Utility retained generation regulatory assets in the first quarter of 2004 (see Note 2 for further discussion). As of December 31, 2004, the Utility has recorded pre-tax offsets to the Settlement Regulatory Asset of approximately $309 million ($183 million after-tax) for supplier settlements and approximately $233 million ($138 million, after-tax) for amortization of the Settlement Regulatory Asset.

The Utility's regulatory asset related to rate reduction bonds is amortized simultaneously with the amortization of the rate reduction bonds liability, and is expected to be recovered by the end of 2007. The Utility's regulatory assets related to deferred income tax will be recovered over the period of reversal of the accumulated deferred taxes to which they relate. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover deferred income tax-related regulatory assets over periods ranging from 1 to 37 years. The Utility's regulatory asset related to the unamortized loss, net of gain, on reacquired debt will be recovered over the remaining original amortization period of the reacquired debt over periods ranging from 1 to 22 years. The Utility's regulatory asset related to environmental compliance represents the portion of the Utility's environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. This amount will be recovered in future rates. The Utility's regulatory assets associated with the plan of reorganization will be recovered over periods ranging from 2 to 30 years. The Utility's regulatory asset relating to post-transition period contract termination costs are being amortized and collected in rates on a straight-line basis until the end of September 2014, the contract's original termination date. This amount will be recovered in future rates.

In general, the Utility does not earn a return on regulatory assets where the related costs do not accrue interest. Accordingly, the only regulatory asset on which the Utility earns a return on is the regulatory assets relating to the Settlement Agreement, retained generation and unamortized loss, net of gain on reacquired debt.

		Balance at December 31,
		2004		2003
		(in millions)
Cost of removal obligation		$	1,990	$	1,810
Asset retirement costs			700		584
Employee benefit plans			687		925
Public purpose programs			191		185
Rate reduction bonds			182		175
Surcharge liability			105		125
Other			180		175

	Total regulatory liabilities	$	4,035	$	3,979

The Utility's regulatory liabilities related to costs of removal represent revenues collected for asset removal costs that the Utility expects to incur in the future. The Utility's regulatory liabilities related to employee benefit plan expenses represent the cumulative differences between expenses recognized for financial accounting purposes and expenses recognized for ratemaking purposes. These balances will be charged against expense to the extent that future financial accounting expenses exceed amounts recoverable for regulatory purposes. The regulatory liability associated with over-recovery of asset retirement costs represents timing differences between the recognition of nuclear decommissioning obligations in accordance with GAAP applicable to non-regulated entities under SFAS No. 143, and the amounts recognized for ratemaking purposes. The Utility's regulatory liability related to public purpose programs represents revenues designated for public purpose program costs that are expected to be incurred in the future. The Utility's regulatory liability for rate reduction bonds represents the deferral of over-collected revenue associated with the rate reduction bonds that the Utility expects to return to customers in the future. For electricity distribution and generation, the Utility collected electricity

revenue and surcharges subject to refund under the frozen rate structure in 2003. The surcharge liability represents the amount of electricity revenue to be refunded.

Sales balancing accounts accumulate differences between revenues and the Utility's authorized revenue requirements. Cost balancing accounts accumulate differences between incurred costs and authorized revenue requirements. Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being credited to customers are recorded as regulatory balancing account liabilities. The Utility's regulatory balancing accounts accumulate balances until they are refunded to or received from the Utility's customers through authorized rate adjustments.

During the California energy crisis, the Utility could not conclude that power generation and procurement-related balancing accounts met the probability requirements of SFAS No. 71. However, the Utility was able to continue to record balancing accounts associated with its electricity transmission and distribution and natural gas transportation businesses.

The Utility's current regulatory balancing account assets comprise the following:

		Balance at December 31,
		2004		2003
		(in millions)
Natural gas revenue balancing accounts		$	76	$	20
Natural gas cost balancing accounts			95		58
Electricity revenue balancing accounts			151		75
Electricity distribution cost balancing accounts			699		95

	Total	$	1,021	$	248

The Utility's current regulatory balancing account liabilities comprise the following:

		Balance at December 31,
		2004		2003
		(in millions)
Natural gas revenue balancing accounts		$	—	$	9
Natural gas cost balancing accounts			34		162
Electricity transmission and distribution revenue balancing accounts			116		6
Electricity transmission cost balancing accounts			219		9

	Total	$	369	$	186

The Utility expects to collect from or refund to its customers the balances included in current balancing accounts receivable and payable within the next twelve months. Regulatory balancing accounts that the Utility does not expect to collect or refund in the next twelve months are included in non-current regulatory assets and liabilities.

Electricity revenues, which are comprised of generation, transmission, and distribution services, are billed to the Utility's customers at the CPUC-approved "bundled" electricity rate. Natural gas revenues, which are comprised of transmission and distribution services, are also billed at CPUC-approved rates. The Utility's revenues are recognized as natural gas and electricity are delivered, and include amounts for services rendered but not yet billed at the end of each year.

As further discussed in Note 12, in January 2001, the California Department of Water Resources, or DWR, began purchasing electricity to meet the portion of demand of the California investor-owned electric utilities that was not being satisfied from their own generation facilities and existing electricity contracts. Under California law, the DWR is deemed to sell the electricity directly to the Utility's retail customers, not to the Utility. Therefore, the Utility acts as a pass-through entity for electricity purchased by the DWR on behalf of its customers. Although charges for electricity provided by the DWR are included in the amounts the Utility bills its customers, the Utility deducts from its electricity revenues the amounts passed through to the DWR. The pass-through amounts are based on the quantities of electricity provided by the DWR that are consumed by customers at the CPUC-approved remittance rate. These pass-through amounts are excluded from the Utility's electricity revenues in its Consolidated Statements of Operations.

PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record its accounts receivables at an estimated net realizable value. The allowance is determined based upon a variety of factors, such as historical write-off experience, delinquency rates, current economic conditions and our assessment of customer collectibility. If circumstances related to the Utility's assumptions change, recoverability estimates are adjusted accordingly.

PG&E Corporation, through the Utility, engages in price risk management activities for non-trading purposes. Price risk management activities include the continuation of power forward contracts that were in existence before the Utility's Chapter 11 proceeding, new power contracts entered into since January 1, 2003 when the Utility resumed procurement of electricity, contracts related to the natural gas and nuclear fuel portfolio, and interest rate hedges related to the issuance of debt under the Utility's plan of reorganization.

Derivative instruments include most forward contracts, futures, swaps, options and other contracts. (Some contracts are accounted for as leases.) Derivative instruments designated as cash flow hedges are entered into to hedge variable price risk associated with the purchase and sale of commodities or to hedge variable interest rates on long-term debt. Additionally, derivative instruments may be eligible for a scope exclusion as further discussed below. For derivative instruments that are not designated as hedges or that are not eligible for a scope exclusion, they are adjusted to fair value through income.

Derivative instruments recorded on PG&E Corporation's and the Utility's Consolidated Balance Sheets are presented in other current assets or other current liabilities. For derivative instruments designated as cash flow hedges associated with non-regulated operations, unrealized gains or losses related to the effective portion of the change in the fair value of the derivative instrument are recorded in accumulated other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of the change in the fair value of the derivative instrument is recognized immediately in earnings. For derivative instruments designated as cash flow hedges associated with the Utility's regulated operations, unrealized gains and losses related to the effective and ineffective portions of the change in the fair value of the derivative instrument to the extent they are recoverable through regulated rates, are deferred and recorded in regulatory accounts.

Hedge accounting is discontinued prospectively if it is determined that the derivative instrument no longer qualifies as an effective hedge, or when the forecasted transaction is no longer probable of occurring. If hedge accounting is discontinued the derivative instrument continues to be reflected at fair value, with any subsequent changes in fair value recognized immediately in earnings. Gains and losses related to a derivative instrument that were previously recorded in accumulated other comprehensive income will remain there until the hedged item is recognized in earnings, unless the forecasted

transaction is probable of not occurring, whereupon the gains and losses from the derivative instrument will be immediately recognized in earnings. The gains and losses deferred in accumulated other comprehensive income are recognized in earnings when the hedged item matures or is exercised.

Net realized and unrealized gains or losses on derivative instruments are included in various lines on PG&E Corporation's and the Utility's Consolidated Statements of Operations, including cost of electricity, cost of natural gas and interest expense. Cash inflows and outflows associated with the settlement of price risk management activities are recognized in operating cash flows on PG&E Corporation's and the Utility's Consolidated Statements of Cash Flows.

The fair value of contracts is estimated using the mid-point of quoted bid and ask forward prices, including quotes from counterparties, brokers, electronic exchanges and published indices, supplemented by online price information from news services. When market data is not available, models are used to estimate fair value.

The Utility has derivative instruments for the physical delivery of commodities transacted in the normal course of business as well as non-financial assets that are not exchange-traded. These derivative instruments are exempt from the requirements of SFAS No. 133 under the normal purchase and sales and non-exchange traded contract exceptions, and are not reflected on the balance sheet at fair value. They are recorded and recognized in income using accrual accounting. Therefore, revenues are recognized as earned and expenses are recognized as incurred.

The Utility has certain commodity contracts for the purchase of nuclear fuel and core gas transportation and storage contracts that are not derivative instruments and are not reflected on the balance sheet at fair value. Revenues are recorded as earned and expenses are recognized as incurred.

PG&E Corporation and the Utility apply the intrinsic-value method prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," in accounting for employee stock-based compensation, as allowed by SFAS No. 123, "Accounting for Stock-Based Compensation," or SFAS No. 123, as amended by SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure, an Amendment of FASB Statement No. 123," or SFAS No. 148. Under the intrinsic-value method, PG&E Corporation and the Utility do not recognize any compensation expense for stock options, as the exercise price is equal to the fair market value of a share of PG&E Corporation common stock at the time the options are granted.

The tables below show the effect on net income and earnings per share for PG&E Corporation and the Utility had it elected to account for its stock-based compensation plans using the fair-value

method under SFAS No. 123 and using the valuation assumptions disclosed in Note 10, for the years ended December 31, 2004, 2003, and 2002:

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

Accumulated other comprehensive income (loss) reports a measure for accumulated changes in equity of an enterprise that results from transactions and other economic events, other than

transactions with shareholders. The following table sets forth the changes in each component of accumulated other comprehensive income (loss):

Accumulated other comprehensive income (loss) included losses related to discontinued operations of approximately $77 million at December 31, 2003 and approximately $93 million at December 31, 2002. During the fourth quarter of 2004, the remaining losses of approximately $77 million included in accumulated other comprehensive income (loss) were recognized in connection with PG&E Corporation's elimination of its equity interest in NEGT.

In December 2004, the FASB issued Statement No. 123 (revised December 2004), "Share-Based Payment," or SFAS No. 123R. SFAS No. 123R requires that the cost resulting from all share-based payment transactions be recognized in the financial statements and establishes a fair-value measurement objective in determining the value of such a cost. SFAS No. 123R will be effective for the third quarter of 2005. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 123R on their Consolidated Financial Statements.

As a result of the California energy crisis, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 on April 6, 2001. The Utility retained control of its assets and was authorized to operate its business as a debtor-in-possession during its Chapter 11 proceeding. PG&E Corporation and the subsidiaries of the Utility, including PG&E Funding LLC, (which issued rate reduction bonds) and PG&E Holdings LLC (which holds stock of the Utility), were not included in the Utility's Chapter 11 proceeding. The Utility recorded its estimate of all valid claims of approximately $9.5 billion as liabilities subject to compromise at December 31, 2003, including interest on disputed claims and approximately $2.7 million of long-term debt.

On April 12, 2004, the Utility emerged from Chapter 11 when its plan of reorganization became effective, or the Effective Date. The plan of reorganization incorporated the terms of the Settlement Agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's Chapter 11 proceeding. Although the Utility's operations are no longer subject to the oversight of the bankruptcy court, the bankruptcy court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of (1) the Settlement Agreement, (2) the plan of reorganization, and (3) the bankruptcy court's December 22, 2003 order confirming the plan of reorganization. In addition, the bankruptcy court retains jurisdiction to resolve remaining disputed claims.

In anticipation of its emergence from Chapter 11, the Utility consummated its public offering of $6.7 billion of First Mortgage Bonds on March 23, 2004. Upon the Effective Date the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon their

resolution, reinstated certain obligations, and paid other obligations. The following table summarizes the sources and uses of funds on the Effective Date:

In connection with the Utility's emergence from Chapter 11, the Utility received investment-grade issuer credit ratings of Baa3 from Moody's Investors Service, or Moody's, and BBB- from Standard & Poor's, or S&P.

On July 15, 2004, the U.S. District Court for the Northern District of California, or the District Court, dismissed the appeals of the bankruptcy court's order confirming the plan of reorganization that had been filed by the two CPUC commissioners who did not vote to approve the Settlement Agreement. These two commissioners appealed the District Court's order to the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. An appeal of the confirmation order filed by the City of Palo Alto remains pending at the District Court. PG&E Corporation and the Utility believe the appeals of the confirmation order are without merit.

In addition, on April 15, 2004, the City and County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet, each filed a petition with the California Court of Appeal seeking review of the CPUC's December 18, 2003 decision approving the Settlement Agreement and the CPUC's March 16, 2004 decision denying applications for rehearing of its December 18, 2003 decision. CCSF and Aglet allege that the Settlement Agreement violates California law, among other claims. CCSF requests that the appellate court hear and review the CPUC's decisions, approving the Settlement Agreement and Aglet requests that the CPUC's decisions be overturned. Three California state senators have filed a brief in support of the CCSF and Aglet petitions. The California Court of Appeal has not yet acted on the petitions. PG&E Corporation and the Utility believe the petitions are without merit and should be denied.

Under applicable federal precedent, once the plan of reorganization has been "substantially consummated," any pending appeals of the confirmation order should be dismissed. If, notwithstanding this federal precedent, the bankruptcy court's confirmation order or the Settlement Agreement is subsequently overturned or modified, PG&E Corporation and the Utility's financial condition and results of operations could be materially adversely affected.

In light of the satisfaction of various conditions to the implementation of the plan of reorganization, including the consummation of the public offering of the First Mortgage Bonds, the

receipt of investment grade credit ratings, and final CPUC approval of the Settlement Agreement, the accounting probability standard required to be met under SFAS No. 71, in order for the Utility to recognize the regulatory assets provided under the Settlement Agreement (as described below), was met as of March 31, 2004. Therefore, the Utility recorded the $2.2 billion, after-tax ($3.7 billion, pre-tax) Settlement Regulatory Asset, and $0.7 billion, after-tax ($1.2 billion, pre-tax), for the Utility retained generation regulatory assets, as summarized in the table below and discussed further in the paragraphs below:

Of the approximately 140,000 acres referred to above, approximately 44,000 acres may be either donated or encumbered with conservation easements. The remaining land contains the Utility's or a joint licensee's hydroelectric generation facilities and may only be encumbered with conservation easements. In the first quarter of 2004, the Utility recorded a $1 million, pre-tax charge to earnings associated with the land donation obligation.

The Settlement Agreement required the Utility to reimburse the CPUC for its professional fees and expenses incurred in connection with the Chapter 11 proceeding. These amounts will be recovered from customers over a reasonable time of up to four years. As of December 31, 2004, the Utility had a regulatory asset of approximately $24 million relating to the CPUC reimbursable fees and expenses. In addition, one of the terms of the Settlement Agreement precluded the Utility from reimbursing PG&E Corporation for certain Chapter 11 related costs. As such, PG&E Corporation reduced its receivable

from the Utility, and the Utility reduced its payable to PG&E Corporation, by approximately $128 million. The transactions were recorded as a contribution of equity to the Utility by PG&E Corporation, net of taxes, and an increase to additional paid-in capital by the Utility in the first quarter 2004.

In November 2004, the CPUC approved the Utility's application for a wholly owned subsidiary to issue ERBs. In December 2004, the Utility received a favorable private letter ruling from the IRS. After satisfaction of all conditions, on February 10, 2005, PG&E Energy Recovery Funding LLC, or PERF, a limited liability company wholly owned and consolidated by the Utility (but legally separate from the Utility), issued the first series of ERBs for approximately $1.9 billion. The Utility, as servicer, will collect DRC charges from customers and remit collected amounts to PERF to enable PERF to pay principal and interest on the ERBs. The proceeds of the first series of ERBs were paid by PERF to the Utility and will be used by the Utility to refinance the remaining unamortized after-tax balance of the Settlement Regulatory Asset through the redemption and repurchase of higher cost equity and debt. The proceeds of the second series of ERBs, anticipated to be issued in November 2005 in an aggregate amount of up to $1.1 billion, will be paid by PERF to the Utility to pre-fund the Utility's recovery through rates of the tax payments that will be due as the Utility collects the DRC over the term of the first series of ERBs to pay principal.

The following table summarizes the disposition of the net creditor claims made in the Utility's Chapter 11 proceeding, the amount of funds held in escrow for the resolution of disputed claims and the disputed claims accrued by the Utility at December 31, 2004:

	(in billions)
Total filed claims in the Utility's Chapter 11 proceeding	$	51.7
ISO, PX and generator claims disallowed		(8.2	)
Other claims disallowed by the bankruptcy court		(25.4	)
Claims objected to by the Utility and pending before the bankruptcy court		(0.1	)
Pass-through claims, including environmental, pending litigation and tort claims⁽¹⁾		(4.7	)
Principal payments made prior to the effectiveness of the plan of reorganization		(2.3	)
Claims settled with the cancellation of bonds owned by the Utility		(0.3	)
Payments on claims on and after the effectiveness of the plan of reorganization⁽²⁾		(8.2	)
Reinstated Pollution Control Bonds		(0.8	)

Amount retained in escrow for remaining disputed claims—principal, at December 31, 2004	$	1.7
Disputed claims not accrued by the Utility		(0.1	)

Net disputed claims accrued by the Utility at December 31, 2004	$	1.6

As of December 31, 2004, the Utility had accrued approximately $1.6 billion for remaining net disputed claims, consisting of approximately $2.1 billion of accounts payable-disputed claims primarily payable to the ISO and the Power Exchange, or the PX, offset by an accounts receivable amount from the ISO and the PX of approximately $0.5 billion. As disclosed in the table above, the Utility held $1.7 billion in escrow for the payment of remaining disputed claims as of December 31, 2004. Although the Utility was required to hold $1.7 billion in escrow, the Utility does not believe it is probable that it will be found liable for approximately $0.1 billion of the $1.7 billion of the disputed claims and, therefore, in accordance with SFAS No. 5, "Accounting for Contingencies," or SFAS No. 5, the Utility has not recorded a liability in its financial statements for this amount. Upon resolution of these claims and under the terms of the Settlement Agreement, any refunds, claims offsets or other credits that the Utility receives from energy suppliers will be returned to customers.

The following table summarizes PG&E Corporation's and the Utility's long-term debt that matures in one year or more from the date of issuance:

On November 15, 2004, PG&E Corporation redeemed the $600 million of 6⁷/8% Senior Secured Notes due 2008, or Senior Secured Notes, in full. Redemption of the Senior Secured Notes required approximately $664.5 million of PG&E Corporation's cash, which included a redemption premium of approximately $50.7 million and $13.8 million of interest accrued since the last interest payment date.

As a result of the Senior Secured Notes redemption, PG&E Corporation wrote off approximately $14.6 million of unamortized loan fees in the three months ended December 31, 2004.

In accordance with SFAS No. 133, the dividend participation rights component is considered to be an embedded derivative instrument and, therefore, must be bifurcated from the Convertible Subordinated Notes and marked to market on PG&E Corporation's Consolidated Statements of Operations as a non-operating expense (in Other expense, net), and reflected at fair value on PG&E Corporation's Consolidated Balance Sheet at December 31, 2004 as $76 million of non-current liability (in Non-current liabilities—other) and $15 million of current liability (in Current liabilities—other). At December 31, 2004, the total estimated fair value of the dividend participation rights component on a pre-tax basis was approximately $91 million.

Concurrent with the negotiation of an amendment of a previously existing credit agreement in June 2002, now paid in full, warrants to purchase 2,397,541 shares of PG&E Corporation's common stock were issued, at an exercise price of $0.01 per share. In October 2002, the above mentioned credit agreement was amended to increase the size of the facility by $300 million to a total of $720 million. In connection with this amendment, PG&E Corporation issued to affiliates of the lenders additional warrants to purchase 2,669,390 shares of PG&E Corporation's common stock, with an exercise price of $0.01 per share. At December 31, 2004, 347,912 of these warrants were outstanding and exercisable with an expiration date of September 2, 2006.

In March 2004, in connection with the implementation of the plan of reorganization, the Utility issued $6.7 billion of First Mortgage Bonds and together with its consolidated subsidiaries, entered into $2.9 billion of credit facilities. The Utility obtained an interim $400 million cash collateralized letter of credit facility, which was terminated on the Effective Date and the letters of credit then outstanding were transferred to the $850 million revolving credit facility.

On March 23, 2004, the Utility closed a public offering of $6.7 billion of First Mortgage Bonds. The First Mortgage Bonds were offered in multiple tranches consisting of 3.60% First Mortgage Bonds due March 1, 2009 in the principal amount of $600 million, 4.20% First Mortgage Bonds due March 1, 2011 in the principal amount of $500 million, 4.80% First Mortgage Bonds due March 1, 2014 in the principal amount of $1 billion, 6.05% First Mortgage Bonds due March 1, 2034 in the principal amount of $3 billion, and Floating Rate First Mortgage Bonds due April 3, 2006 in the principal amount of

$1.6 billion. The Utility received proceeds of $6.7 billion from the offering, net of a discount of $18 million. The interest rate for the Floating Rate First Mortgage Bonds is based on the three-month London Interbank Offered Rate, or LIBOR, plus 0.70%, which resets quarterly. The next reset date is April 3, 2005. For 2004, the average interest rate on the Floating Rate First Mortgage Bonds was 4.8%.

On October 3, 2004, the Utility partially redeemed Floating Rate First Mortgage Bonds due in 2006 in the aggregate principal amount of $500 million. On January 3, 2005, the Utility partially redeemed Floating Rate First Mortgage Bonds due in 2006 in the aggregate principal amount of $300 million. In addition, the Utility plans to use a portion of the energy recovery bond proceeds to defease $600 million of Floating Rate First Mortgage Bonds by the end of February 2005.

In addition, approximately $2.5 billion of additional First Mortgage Bonds have been issued as security to various banks and insurance companies under the following agreements (1) the Utility's $620 million letters of credit backing pollution control bonds, (2) the Utility's reimbursement obligation under an insurance policy relating to $200 million in pollution control bonds that were issued for the benefit of the Utility, (3) the Utility's $345 million loan agreements with the California Pollution Control Financing Authority, or the CPCFA, (4) the Utility's $454 million reimbursement agreements for pollution control bond bridge facilities, and (5) the Utility's $850 million working capital facility.

The First Mortgage Bonds are secured by a first lien, subject to permitted exceptions, on substantially all of the Utility's real property and certain tangible personal property related to the Utility's facilities. Subject to certain conditions, the Utility will be entitled to terminate the lien and eliminate all terms and conditions relating to collateral for the First Mortgage Bonds on the release date. In general, the release date will occur when the Utility provides written evidence to the trustee of the First Mortgage Bonds that the ratings on the Utility's long-term unsecured debt obligations following the release date would at least equal the (1) initial ratings assigned by Moody's and S&P on the First Mortgage Bonds, or (2) comparable ratings by any other nationally recognized rating agency or agencies selected by the Utility if either Moody's or S&P do not then rate the Utility's long-term unsecured debt obligations. The First Mortgage Bonds received initial investment grade credit ratings of Baa2 from Moody's and BBB from S&P.

If the lien securing the First Mortgage Bonds is released, the indenture will limit the ability of the Utility and its significant subsidiaries to incur secured debt and enter into sale and leaseback transactions.

Under pollution control loan agreements, the Utility is obligated to reimburse the CPCFA for funds received by the Utility from the issuance of the CPCFA's pollution control bonds for the benefit of the Utility. The principal amount of these loan obligations totaled $814 million at December 31, 2004. Interest rates on $614 million of $814 million of the obligations are variable. For 2004, the average variable interest rates ranged from 1.19% to 1.21%. The interest rate on the remaining $200 million of the obligations is fixed at 5.35%.

The CPCFA pollution control bonds in the principal amount of $200 million are backed by bond insurance. The CPCFA pollution control bonds in the principal amount of $614 million are backed by letters of credit of $620 million. The Utility's reimbursement obligations are supported by $820 million in First Mortgage Bonds that have been issued to the bond insurer and letter of credit banks. These bank agreements supplying the letters of credit include a covenant requiring the Utility to maintain, as of the end of each fiscal quarter ending after the Effective Date, a debt to capitalization ratio of at most 65%.

Drawings for interest due under the loan agreements are made under these letters of credit on each scheduled interest payment date, which is the first business day of each month. On the same day, the Utility pays the amount of the draw to the letter of credit banks per the terms of the reimbursements agreements. The letters of credit are then reinstated to the full amount of their initial commitments.

Pollution Control Bond Term Loan Facility and 3.5% Pollution Control Loan Agreements

On the Effective Date, the Utility entered into a $345 million term loan facility that was used to fund the Utility's purchase, in lieu of redemption, of the CPCFA's Pollution Control Revenue Bonds, 1992 Series A and B and 1993 Series A and B, or collectively the Old Bonds.

On June 29, 2004, the Utility entered into four separate loan agreements, each dated as of June 1, 2004, with the CPCFA, which issued $345 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, 2004 Series A ($70 million), 2004 Series B ($90 million), 2004 Series C ($85 million), and 2004 Series D ($100 million), or collectively the New Bonds, to refund the Old Bonds. The funds made available from the refund of Old Bonds were used to repay the $345 million term loan facility. Principal and interest payments on the New Bonds are backed by bond insurance and the Utility's obligations under the new loan agreements are supported by $345 million of First Mortgage Bonds that are held by the trustee for the New Bonds.

During the Utility's Chapter 11 proceeding, approximately $454 million in aggregate principal amount of pollution control bonds, which were issued for the Utility's benefit and were credit enhanced with letters of credit were redeemed through draws on the letters of credit. On the Effective Date, the Utility executed bridge loans with new lenders who had purchased the $454 million reimbursement obligations owed by the Utility to the letter of credit issuers and entered into four separate amended and restated reimbursement agreements with new lenders. These reimbursement agreements include a covenant requiring the Utility to maintain, as of the end of each fiscal quarter ending after the Effective Date, a debt to capitalization ratio of at most 65%. The Utility intends to refinance the $454 million with long-term tax-exempt bonds or taxable debt. The outstanding balance of $454 million at December 31, 2004 under the amended and restated reimbursement agreements is due and payable on June 5, 2005. At the Utility's request and at the sole discretion of each lender, each amended and restated reimbursement agreement may be extended for additional periods. On the Effective Date, the Utility supported its obligations under the amended and restated reimbursement agreement with $454 million of First Mortgage Bonds.

At December 31, 2004, PG&E Corporation's and the Utility's combined aggregate amounts of maturing long-term debt as scheduled are reflected in the table below:

The following table summarizes PG&E Corporation's and the Utility's short-term borrowings and outstanding credit facilities at December 31, 2004 and 2003. The Utility's credit facilities and short-term borrowings subject to compromise at December 31, 2003 were paid and cancelled on the Effective Date. At December 31, 2004, PG&E Corporation did not have any outstanding balances on its credit facilities. At December 31, 2004, the Utility had $300 million in short-term borrowings outstanding under the $850 million revolving credit facility, or working capital facility and approximately $285 million of letters of credit outstanding. There were no other outstanding balances on the Utility's

credit facilities at December 31, 2004. PG&E Corporation and the Utility's, including their consolidated subsidiaries, short-term borrowings and other credit facilities consist of the following:

On December 10, 2004, PG&E Corporation entered into a $200 million three-year revolving senior unsecured credit facility, or senior credit facility, with a syndicate of lenders. The aggregate facility of $200 million includes a $50 million sublimit for the issuance of letters of credit and a $100 million sublimit for swing line loans. Borrowings under the senior credit facility and letters of credit will be used primarily for working capital and other corporate purposes. The senior credit facility has a term of three years and all outstanding amounts are due and payable on December 10, 2007. PG&E Corporation can, at any time, repay amounts outstanding in whole or in part. At PG&E Corporation's request and at the sole discretion of each lender, the senior credit facility may be extended for additional periods. PG&E Corporation has the right to increase, in one or more requests given no more than once a year, the aggregate facility by up to $100 million provided certain conditions are met. At December 31, 2004, PG&E Corporation had not undertaken any borrowings or issued any letters of credit under the senior credit facility.

Borrowings under the senior credit facility bear interest based, at PG&E Corporation's election, on a Eurodollar rate or a base rate, plus an applicable margin. The base rate equals the higher of the administrative agent-announced base rate or 0.5% above the federal funds rate. Interest is payable by PG&E Corporation at least quarterly, or earlier for loans with shorter interest periods. In addition, a facility fee based on the aggregate facility and a utilization fee based on the average daily amount outstanding under the senior credit facility are payable by PG&E Corporation quarterly in arrears (the utilization fee is levied during any quarter in which the average daily amount outstanding is in excess of 50% of the aggregate facility). The applicable margin, facility fee and utilization fee fluctuate with the Utility's credit rating. The applicable margin ranges between 0.70% and 1.35% for Eurodollar loans and 0% and 0.5% for base rate loans. The facility fee ranges between 0.175% and 0.4% and the utilization fee ranges between 0.125% and 0.25%.

Amounts outstanding under letter of credit arrangements bear interest at the Eurodollar rate plus applicable margin, as detailed above. Interest, a fronting fee, to be determined between PG&E Corporation and the issuing lender, and normal lender costs of issuing and negotiating letter of credit arrangements are payable quarterly in arrears.

The senior credit facility includes covenants requiring that PG&E Corporation maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% and that PG&E Corporation own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting securities of PG&E Corporation.

On March 5, 2004, the Utility entered into certain agreements providing for the continuous sale of a portion of the Utility's accounts receivable to PG&E Accounts Receivable Company, LLC, or PG&E ARC, a limited liability company wholly owned by the Utility. In turn, PG&E ARC sells interests in its accounts receivable to commercial paper conduits or banks. PG&E ARC may obtain up to $650 million of financing under such agreements. The borrowings under this facility bear interest at commercial paper rates and a fixed margin based on the Utility's credit ratings. Interest on the facility is payable monthly. The maximum amount available for borrowing under this facility changes based upon the amount of eligible receivables, concentration of eligible receivables and other factors. The credit facility will terminate on March 5, 2007. The Utility began selling accounts receivables to PG&E ARC on the Effective Date and used the proceeds from the sale of the accounts receivable in connection with this credit facility to pay allowed claims on the Effective Date. On May 7, 2004, PG&E ARC paid off this

credit facility, and on December 31, 2004, there were no amounts drawn on the credit facility. Although PG&E ARC is a wholly owned consolidated subsidiary of the Utility, PG&E ARC is legally separate from the Utility. The assets of PG&E ARC (including the accounts receivable) are not available to creditors of the Utility or PG&E Corporation, and the accounts receivable are not legally assets of the Utility or PG&E Corporation. For the purposes of financial reporting, the credit facility is accounted for as a secured financing.

The accounts receivable facility includes a covenant from the Utility requiring it to maintain, as of the end of each fiscal quarter ending after the Effective Date, a debt to capitalization ratio of at most 65%.

On March 5, 2004, the Utility entered into an $850 million revolving credit facility, or working capital facility, with a syndicate of banks. Loans under the working capital facility will be used primarily to cover operating expenses and seasonal fluctuations in cash flows. Letters of credit under the working capital facility will be used primarily to provide credit enhancements to counter parties for natural gas and electricity procurement transactions. The working capital facility has a term of three years and all outstanding amounts will be due and payable on March 5, 2007. At the Utility's request and at the sole discretion of each lender, the working capital facility may be extended for additional periods. On the Effective Date, the Utility supported its obligation under the working capital facility with First Mortgage Bonds. At December 31, 2004, there were $300 million of loans outstanding under the working capital facility, which had a weighted average interest rate of 3.42%. The Utility repaid the $300 million of loans outstanding on February 11, 2005. The Utility also had approximately $285 million of letters of credit outstanding at December 31, 2004.

On March 2, 2004, the Utility entered into a cash collateralized $400 million letter of credit facility that was used to issue letters of credit to provide credit support in connection with the Utility's pre-existing and new natural gas procurement activities and related purchases of natural gas transportation services. As discussed above, this credit facility was terminated on the Effective Date, and the outstanding balance of letters of credit was transferred to the $850 million working capital facility.

In December 1997, PG&E Funding, LLC, a limited liability corporation wholly owned by and consolidated by the Utility, issued $2.9 billion of rate reduction bonds. The proceeds of the rate reduction bonds were used by PG&E Funding, LLC to purchase from the Utility the right, known as "transition property," to be paid a specified amount from a non-bypassable charge levied on residential and small commercial customers (Fixed Transition Amount, or FTA, charges). FTA charges are authorized by the CPUC under state legislation and will be paid by residential and small commercial

customers until the rate reduction bonds are fully retired. Under the terms of a transition property servicing agreement, FTA charges are collected by the Utility and remitted to PG&E Funding, LLC. As a result of credit rating downgrades in January 2001, on January 8, 2001, the Utility was required to begin remitting these FTA receipts to PG&E Funding, LLC on a daily basis, as opposed to once a month, as had previously been required.

The rate reduction bonds have expected maturity dates ranging from 2005 to 2007, and bear interest at rates ranging from 6.42% to 6.48%. The bonds are secured solely by the transition property and there is no recourse to the Utility or PG&E Corporation.

The total amount of rate reduction bonds principal outstanding was $870 million at December 31, 2004 and $1.16 billion at December 31, 2003. The scheduled principal payments on the rate reduction bonds for the years 2005 through 2007 are $290 million for each year. While PG&E Funding, LLC is a wholly owned consolidated subsidiary of the Utility, it is legally separate from the Utility. The assets of PG&E Funding, LLC are not available to creditors of the Utility or PG&E Corporation, and the transition property is not legally an asset of the Utility or PG&E Corporation.

Effective July 8, 2003 (the date NEGT filed a voluntary petition for relief under Chapter 11), NEGT and its subsidiaries were no longer consolidated by PG&E Corporation in its Consolidated Financial Statements. Under GAAP, consolidation is generally required for entities owning more than 50% of the outstanding voting stock of an investee, except when control is not held by the majority owner. Legal reorganization and bankruptcy represent conditions that can preclude consolidation in instances where control rests with an entity other than the majority owner. In anticipation of NEGT's Chapter 11 filing, PG&E Corporation's representatives who previously served on the NEGT Board of Directors resigned on July 7, 2003, and were replaced with Board members who were not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retained significant influence over the ongoing operations of NEGT.

Accordingly, at December 31, 2003, PG&E Corporation's net negative investment in NEGT of approximately $1.2 billion was reflected as a single amount, under the cost method, within the December 31, 2003 Consolidated Balance Sheet of PG&E Corporation. This negative investment represents the losses of NEGT recognized by PG&E Corporation in excess of its investment in and advances to NEGT.

On October 29, 2004, NEGT's plan of reorganization became effective, at which time NEGT emerged from Chapter 11 and PG&E Corporation's equity ownership in NEGT was cancelled. On the effective date, PG&E Corporation reversed its negative investment in NEGT and also reversed net deferred income tax assets of approximately $428 million and a charge of approximately $120 million ($77 million, after tax), in accumulated other comprehensive income, related to NEGT. The resulting net gain has been offset by the $30 million payment made by PG&E Corporation to NEGT pursuant to the parties' settlement of certain tax-related litigation and other adjustments to NEGT-related liabilities. A summary of the effect on the quarter and year ended December 31, 2004 earnings from discontinued operations is as follows:

	(in millions)
Investment in NEGT	$	1,208
Accumulated other comprehensive income		(120	)
Cash paid pursuant to settlement of tax related litigation		(30	)
Tax effect		(374	)

Gain on disposal of NEGT, net of tax	$	684

Included within earnings from discontinued operations on the Consolidated Statements of Operations of PG&E Corporation are NEGT's operating results, summarized below:

Prior to July 8, 2003, NEGT had accounted for certain of its subsidiaries as discontinued operations. The operating results shown above reflect the operating results of USGen New England, Inc. through July 7, 2003 and the other previously discontinued operations through the respective disposal dates. The 2003 pre-tax loss of NEGT and its subsidiaries includes the following gains and losses on disposal of those subsidiaries: a pre-tax gain of approximately $19 million on disposal related to the sale of Mountain View Power Partners, LLC in January 2003, an additional pre-tax loss of approximately $3 million on disposal related to the sale of PG&E Energy Trading, Canada Corporation in the first quarter of 2003, and a pre-tax loss of approximately $9 million on disposal related to the sale of certain Ohio generating plants and related equipment in the second quarter of 2003. Also included in the 2003 pre-tax loss are impairments, write-offs, and other charges of approximately $229 million.

The 2002 pre-tax loss of NEGT and its subsidiaries includes the following gains and losses on disposal of subsidiaries: a pre-tax loss of approximately $25 million on the anticipated disposition of PG&E Energy Trading, Canada Corporation in the fourth quarter 2002, subsequently disposed of in 2003 as described above, and a $1.1 billion pre-tax loss for USGen New England deemed discontinued operations in the fourth quarter 2002. Also included in the 2002 pre-tax loss of NEGT and its subsidiaries are impairments, write-offs, and other charges of approximately $2.8 billion.

During the second quarter of 2003, NEGT determined that its historical financial reporting presentation of revenues and expenses related to hedging and certain ISO purchase and sales transactions had not been consistent. Certain types of transactions had been reported on a net basis (whereby revenues had been offset by the related expense item) and other types of transactions had been reported on a gross basis. In order to provide a consistent reporting of its trading and hedging transactions, NEGT adopted a net presentation approach for such transactions. PG&E Corporation believes that this method of presentation is preferable under the circumstances. Adopting this change reduced previously reported revenues and expenses of NEGT by approximately $843 million for the year ended December 31, 2002. In addition, adjustments were made principally for the effects of transactions that had not previously been eliminated in consolidation by NEGT. Such adjustments decreased previously reported revenues and expenses by approximately $671 million for the year ended December 31, 2002. These changes did not result in any change in consolidated operating income or net income, in the Consolidated Statements of Operations.

As a result of the adoption of DIG C15 and C16, NEGT recognized net losses in 2002 related to the cumulative effect of a change in accounting principle of $61 million, after-tax. As a result of the adoption of SFAS No. 143, NEGT recognized net losses in 2003 related to a change in accounting principle of $5 million, after-tax.

On October 29, 2004, the effective date of NEGT's plan of reorganization, amounts due as a result of NEGT affiliates' defaults on numerous agreements were determined and resolved. PG&E Corporation is not a party to these agreements, nor does it anticipate any obligation related to these agreements.

PG&E Corporation has authorized 800 million shares of no-par common stock of which 418,616,141 shares were issued and outstanding at December 31, 2004 and 416,520,282 were issued and outstanding at December 31, 2003. A wholly owned subsidiary of PG&E Corporation, Elm Power Corporation, holds 24,665,500 shares of the outstanding shares.

During the fourth quarter of 2004, 1,863,600 shares of PG&E Corporation common stock were repurchased through transactions with brokers and dealers on the New York Stock Exchange and/or the Pacific Exchange for an aggregate purchase price of approximately $60 million. Of this amount, 850,000 shares were purchased at a cost of approximately $28 million and are held by Elm Power Corporation.

On December 15, 2004, PG&E Corporation entered into an accelerated share repurchase agreement with Goldman, Sachs & Co., or GS&Co., under which PG&E Corporation repurchased 9,769,600 shares of its outstanding common stock for an aggregate purchase price of approximately $318 million, at an initial price of $32.50 per share. The repurchase was funded from available cash on hand. The repurchased shares have been retired as of December 20, 2004. Under this arrangement, PG&E Corporation has an obligation to pay GS&Co. a price adjustment based on the daily volume weighted average market price of PG&E Corporation common stock over the term of the arrangement. The price adjustment can be settled, at PG&E Corporation's option, in cash or in shares of its common stock and is accounted for as equity. The number of shares that PG&E Corporation would issue in settlement of the price adjustment feature is capped at approximately 19.5 million shares. At December 31, 2004, this price adjustment obligation amounted to approximately $7.4 million. If this obligation were settled in shares at December 31, 2004, PG&E Corporation would have issued approximately 222,000 shares. PG&E Corporation expects the arrangement to terminate on February 22, 2005, and to pay GS&Co. approximately $14 million to settle its obligations.

On December 15, 2004, the Board of Directors of the Utility authorized the repurchase of up to $800 million, (which has been increased to $1.8 billion following the receipt of proceeds from the issuance of ERBs) of the Utility's common stock from PG&E Corporation, with such repurchases to be effective from time to time, but no later than December 31, 2006. It was previously anticipated that the first series of ERBs would be issued as early as January 2005. Based on this expectation, on December 15, 2004, PG&E Corporation's Board of Directors authorized the repurchase of up to $975 million of its outstanding common stock. On February 16, 2005, this authorization was increased to $1.05 billion. PG&E Corporation expects to enter into a replacement accelerated share repurchase arrangement by the end of February or early March 2005 to repurchase an aggregate of $1.05 billion of its outstanding shares. The repurchased shares will be retired at that time.

PG&E Corporation repurchased and retired 6,580 shares of its common stock, at a cost of $102,274 during the year ended December 31, 2002. There were no stock repurchases during the year ended December 31, 2003.

Of the 418,616,141 shares issued and outstanding at December 31, 2004, 1,601,710 shares are PG&E Corporation restricted stock granted under the PG&E Corporation long-term incentive program. Further, PG&E Corporation issues common stock in connection with employee benefit plans. See Note 10 for further discussion.

PG&E Corporation previously issued warrants to purchase 5,066,931 shares of its common stock at an exercise price of $0.01 per share to lenders during 2002. During 2004, 4,003,812 shares of PG&E Corporation common stock were issued upon the exercise of the warrants. At December 31, 2004, 347,912 of these warrants were outstanding and exercisable with an expiration date of September 2, 2006.

PG&E Corporation did not declare or pay common or preferred stock dividends in 2004, 2003 or 2002.

The Utility is authorized to issue 800 million shares of its $5 par value common stock, of which 321,314,760 shares were issued and outstanding as of December 31, 2004 and 2003. PG&E Holdings, LLC, a wholly owned subsidiary of the Utility, holds 19,481,213 of the outstanding shares. PG&E Corporation and PG&E Holdings, LLC hold all of the Utility's outstanding common stock. Approximately 94% of the outstanding common stock of the Utility that is owned by PG&E Corporation was pledged as security for PG&E Corporation's Senior Secured Notes. On November 15, 2004, PG&E Corporation redeemed these notes in full and the pledge was released.

The Utility may pay common stock dividends and repurchase its common stock provided cumulative preferred dividends on its preferred stock and mandatory preferred sinking fund payments are paid. As further discussed in Note 7, upon emergence from Chapter 11, the Utility paid cumulative preferred dividends as of December 31, 2004 and preferred sinking fund payments related to 2004, 2003, and 2002.

PG&E Corporation has authorized 85 million shares of preferred stock, which may be issued as redeemable or non-redeemable preferred stock. No preferred stock of PG&E Corporation has been issued or is outstanding.

The Utility has authorized 75 million shares of $25 par value preferred stock, which may be issued as redeemable or non-redeemable preferred stock.

At December 31, 2004 and 2003, the Utility had issued and outstanding 5,784,825 shares of non-redeemable preferred stock. Holders of the Utility's 5.0%, 5.5% and 6.0% series of non-redeemable preferred stock have rights to annual dividends ranging from $1.25 to $1.50 per share.

At December 31, 2004 and 2003, the Utility had issued and outstanding 5,973,456 shares of redeemable preferred stock. The Utility's redeemable preferred stock is subject to redemption at the Utility's option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2004, annual dividends ranged from $1.09 to $1.76 per share and redemption prices ranged from $25.75 to $27.25 per share.

At December 31, 2004, the Utility's redeemable preferred stock with mandatory redemption provisions consisted of 2.55 million shares of the 6.57% series and 2.375 million shares of the 6.30% series. These series are redeemable at par value plus accumulated and unpaid dividends through the redemption date. These series of preferred stock are subject to mandatory redemption provisions entitling them to sinking funds providing for the retirement of the stock outstanding.

The redemption requirements for the Utility's redeemable preferred stock with mandatory redemption provisions for the 6.57% series are approximately $4 million per year from 2002 through 2006, and approximately $55 million in 2007, and for the 6.30% series, approximately $3 million per year from 2004 through 2008, and approximately $47 million in 2009. The Utility's redeemable preferred stock with mandatory redemption provisions may be redeemed early, at the Utility's option, if the Utility pays the specified redemption price plus accumulated and unpaid dividends. In 2004, subsequent to the Utility's emergence from Chapter 11, the Utility redeemed $15 million of preferred stock with mandatory redemption provisions related to 2004, 2003, and 2002.

Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights. Due to the Utility's Chapter 11 proceeding, the Utility's Board of Directors did not declare or pay preferred stock dividends from January 31, 2001 through emergence from Chapter 11. Upon emergence from Chapter 11 on the Effective Date, the Utility paid approximately $101 million of preferred stock dividends, including approximately $11 million of interest on these dividends, as of December 31, 2004. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series.

PG&E Corporation and the Utility adopted the requirements of SFAS No. 150 in 2003. As a result, the Utility reclassified approximately $137 million of preferred stock with mandatory redemption provisions as a noncurrent liability in the Utility's Consolidated Balance Sheets. The reclassification did not have an impact on earnings of PG&E Corporation or the Utility. At December 31, 2004, $122 million of such preferred stock remained on the Utility's Consolidated Balance Sheet.

As discussed in Note 5, NEGT financial results are no longer consolidated with those of PG&E Corporation following the July 8, 2003 Chapter 11 filing of NEGT. NEGT's financial results through July 7, 2003 are reflected in discontinued operations. Because NEGT financial results are no longer consolidated with those of PG&E Corporation, the only risk management activities currently reported by PG&E Corporation are related to Utility non-trading activities, which are executed on a non-trading basis.

On the Utility's Consolidated Balance Sheets, price risk management activities are presented at fair value of $5 million in other current assets and $11 million in other current liabilities for December 31, 2004 and $8 million in other current assets for December 31, 2003. The costs of these derivatives are recovered in regulated rates charged to customers and the Utility records the offset to the regulatory accounts.

At December 31, 2004, the Utility had no cash flow hedges associated with interest rate risk. At December 31, 2003, the Utility had cash flow hedges associated with interest rate risk presented at fair value of approximately $17 million in other current assets and approximately $3 million in accumulated other comprehensive loss, net of tax. These hedges were associated with non-regulated operations and expired in the first quarter of 2004.

The ineffective portion of changes in amounts of the Utility's cash flow hedges associated with interest rate risk was approximately $3 million for the year ended December 31, 2004 and approximately $4 million for the year ended December 31, 2003.

Credit risk is the risk of loss that PG&E Corporation and the Utility would incur if customers or counterparties failed to perform their contractual obligations.

PG&E Corporation had gross accounts receivable of approximately $2.2 billion at December 31, 2004 and $2.5 billion at December 31, 2003. The majority of the accounts receivable are associated with the Utility's residential and small commercial customers. Based upon historical experience and evaluation of then-current factors, allowances for doubtful accounts of approximately $93 million at December 31, 2004 and $68 million at December 31, 2003 were recorded against those accounts receivable. In accordance with tariffs, credit risk exposure is limited by requiring deposits from new customers and from those customers whose past payment practices are below standard. The Utility has a regional concentration of credit risk associated with its receivables from residential and small commercial customers in northern and central California. However, material loss due to non-performance from these customers is not considered likely.

The Utility manages credit risk for its largest customers or counterparties by assigning credit limits based on an evaluation of their financial condition, net worth, credit rating, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored frequently and a detailed credit analysis is performed at least annually.

Credit exposure for the Utility's largest customers and counterparties is calculated daily. If exposure exceeds the established limits, the Utility takes immediate action to reduce the exposure or obtain additional collateral, or both. Further, the Utility relies heavily on master agreements that require security, referred to as credit collateral, in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.

The Utility calculates gross credit exposure for each of its wholesale customers and counterparties as the current mark-to-market value of the contract (i.e., the amount that would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, before the application of credit collateral. During 2004, the Utility recognized no material losses due to contract defaults or bankruptcies. At December 31, 2004 there were three counterparties that represented greater than 10% of the Utility's net credit exposure. Of these three counterparties, two were investment grade representing a total of approximately 47% of the Utility's net wholesale credit exposure and one was below-investment grade representing approximately 17% of the Utility's net wholesale credit exposure.

The schedule below summarizes the Utility's net credit risk exposure, as well as the Utility's credit risk exposure to its wholesale customers or counterparties with a greater than 10% net credit exposure, at December 31, 2004 and December 31, 2003:

The schedule below summarizes the credit quality of the Utility's net credit risk exposure to the Utility's wholesale customers and counterparties at December 31, 2004 and December 31, 2003:

		Net Credit Exposure⁽²⁾		Percentage of Net Credit Exposure
		(in millions)
Credit Quality⁽¹⁾ December 31, 2004
	Investment grade⁽³⁾	$	79	81	%
	Non-investment grade		19	19	%

Total		$	98	100	%

December 31, 2003
	Investment grade⁽³⁾	$	108	70	%
	Non-investment grade		46	30	%

Total		$	154	100	%

Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility's nuclear power facilities consist of two units at the Diablo Canyon power plant and the retired facility at Humboldt Bay Unit 3. For ratemaking purposes, the eventual decommissioning of Diablo Canyon Unit 1 is scheduled to begin in 2021 and to be completed in 2040. Decommissioning of Diablo Canyon Unit 2 is scheduled to begin in 2025 and to be completed in 2041, and decommissioning of Humboldt Bay Unit 3 is scheduled to begin in 2009 and be completed in 2015.

The estimated nuclear decommissioning cost for the Diablo Canyon power plant and Humboldt Bay Unit 3 is approximately $1.89 billion in 2004 dollars (or approximately $5.25 billion in future dollars). These estimates are based on a 2002 decommissioning cost study and are prepared in accordance with CPUC requirements and are used in the Utility's Nuclear Decommissioning Costs Triennial Proceeding. The Utility's revenue requirements for nuclear decommissioning costs are recovered from customers through a non-bypassable charge that will continue until those costs are fully recovered. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear plants. Actual decommissioning costs are expected to vary from these estimates because of changes in assumed dates of decommissioning, regulatory requirements, technology, costs of labor, materials and equipment.

The estimated nuclear decommissioning cost described above is used for regulatory purposes. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. However, under GAAP requirements, the decommissioning cost estimate is calculated using a different method. In accordance with SFAS No. 143, the Utility adjusts its nuclear decommissioning obligation to reflect the fair value of decommissioning its nuclear power facilities. The Utility records the Utility's total nuclear decommissioning obligation as an asset retirement obligation on the Utility's Consolidated Balance Sheet. The total nuclear decommissioning obligation accrued in accordance with GAAP was approximately $1.2 billion at December 31, 2004 and $1.1 billion at December 31, 2003. The primary difference between the Utility's estimated nuclear decommissioning obligation as recorded in accordance with GAAP and the estimate prepared in accordance with the CPUC requirements is that GAAP incorporates various potential settlement dates for the obligation and includes an estimated amount for third party labor costs into the fair value calculation.

The Utility has three decommissioning trusts for its Diablo Canyon and Humboldt Bay Unit 3 nuclear facilities. The Utility has elected that two of these trusts be treated under the Internal Revenue Code as qualified trusts. If certain conditions are met, the Utility is allowed a deduction for the payments made to the qualified trusts. These payments cannot exceed the amount collected from customers through the decommissioning charge. The qualified trusts are subject to a lower tax rate on income and capital gains, thereby increasing the trusts' after-tax returns. Among other requirements, to maintain the qualified trust status the IRS must approve the amount to be contributed to the qualified trusts for any taxable year. The remaining non-qualified trust is exclusively for decommissioning Humboldt Bay Unit 3. The Utility cannot deduct amounts contributed to the non-qualified trust until such decommissioning costs are actually incurred.

In October 2003, the CPUC issued a decision in the 2002 Nuclear Decommissioning Costs Triennial Proceeding (covering 2003 through 2005) finding that the funds in the Diablo Canyon nuclear decommissioning trusts are sufficient to pay for the Diablo Canyon power plant's eventual decommissioning. In 2004, the Utility was authorized to collect approximately $18.4 million in rates and contributed approximately $18.4 million to the qualified nuclear decommissioning trust for Humboldt Bay Unit 3. For 2005, the Utility is authorized to collect approximately $18.4 million in rates for decommissioning Humboldt Bay Unit 3. Of this amount, the Utility expects to contribute approximately $18.4 million to the qualified trusts for Humboldt Bay Unit 3. The Utility received approval from the

IRS to contribute a portion of the collected amount to the qualified trust for Humboldt Bay Unit 3. The Utility has requested the IRS approve a revised ruling for the total amount collected to be contributed to the qualified trust for Humboldt Bay Unit 3. If the IRS does not approve the revised ruling request, the Utility must withdraw contributions it made to the qualified trust for 2004 and 2005 in excess of the current IRS ruling amount and contribute the excess amounts, on an after-tax basis, to the non-qualified trust. The Utility would likely request that the CPUC approve an increase in revenue requirements to make up for the reduced amount contributed to the non-qualified trust due to the reduced rate of return attributable to taxes.

The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility's nuclear facilities. The trusts maintain substantially all of their investments in debt and equity securities. The CPUC has authorized the qualified trust to invest a maximum of 50% of its funds in publicly traded equity securities, of which up to 20% may be invested in publicly traded non-US equity securities. For the non-qualified trust, no more than 60% may be invested in publicly traded equities. The allocation of the trust funds is monitored monthly. To the extent that market movements cause the asset allocation to move outside these ranges, the investments are rebalanced toward the target allocation.

The Utility estimates after-tax annual earnings, including realized gains and losses, in the qualified trusts to be 6.5% and in the non-qualified trusts to be 5.6%. Annual returns decrease in later years as higher portions of the trusts are dedicated to fixed income investments leading up to and during the entire course of decommissioning activities.

All earnings on the assets held in the trusts, net of authorized disbursements from the trusts and investment management and administrative fees, are reinvested. Amounts may not be released from the decommissioning trusts until authorized by the CPUC. At December 31, 2004, the Utility had accumulated nuclear decommissioning trust funds with an estimated fair value of approximately $1.6 billion, based on quoted market prices and net of deferred taxes on unrealized gains.

In general, investment securities are exposed to various risks, such as interest rate, credit and market volatility risks. Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the market values of investment securities could occur in the near term, and such changes could materially affect the trusts' fair value.

The Utility records unrealized gains and losses on investments held in the trusts in other comprehensive income in accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Realized gains and losses are recognized as additions or reductions to trust asset balances. The Utility, however, accounts for its nuclear decommissioning obligations in accordance with SFAS No. 71. Therefore, both realized and unrealized gains and losses are ultimately recorded in regulatory asset or liability accounts.

The following table provides a summary of the fair value, based on quoted market prices, of the investments held in the Utility's nuclear decommissioning trusts:

	Maturity Date	Total Unrealized Gains		Total Unrealized Losses			Estimated Fair Value
	(in millions)
Year ended December 31, 2004
U.S. government and agency issues	2005-2033	$	47	$	—		$	681
Municipal bonds and other	2005-2034		14		—			181
Equity securities			523		—			880

Total		$	584	$	—		$	1,742

Year ended December 31, 2003
U.S. government and agency issues	2004-2032	$	47	$	—		$	586
Municipal bonds and other	2004-2034		11		—			147
Equity securities			409		(1	)		790

Total		$	467	$	(1	)	$	1,523

The cost of debt and equity securities sold is determined by specific identification. The following table provides a summary of the activity for the debt and equity securities:

	Year Ended December 31,
	2004		2003			2002
	(in millions)
Proceeds received from sales of securities	$	1,821	$	1,087		$	1,631
Gross realized gains on sales of securities held as available-for-sale		28		27			51
Gross realized losses on sales of securities held as available-for-sale		22		(44	)		(91	)

Under the Nuclear Waste Policy Act of 1982, the Department of Energy, or the DOE, is responsible for the permanent storage and disposal of spent nuclear fuel. The Utility has signed a contract with the DOE to provide for the disposal of spent nuclear fuel and high-level radioactive waste from the Utility's nuclear power facilities. Under the Utility's contract with the DOE, if the DOE completes a storage facility by 2010, the earliest that Diablo Canyon's spent fuel would be accepted for storage or disposal would be 2018. At the projected level of operation for Diablo Canyon, the Utility's current facilities are able to store on-site all spent fuel produced through approximately 2007. The NRC granted authorization in March 2004 to build an on-site dry cask storage facility to store spent fuel through approximately 2021 for Unit 1 and to 2024 for Unit 2. However, several intervenors in that proceeding filed an appeal of the NRC's decision with the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. Oral arguments on that appeal are expected in the first quarter of 2005 with a decision anticipated in the second half of 2005. Construction of the on-site dry cask storage facility is expected to start in the second quarter of 2005 after grading permits are obtained from the County of San Luis Obispo. To provide another storage alternative in the event construction of the dry cask storage facility is delayed, the Utility has also requested that the NRC approve another storage option to install a temporary storage rack in each unit's existing spent fuel storage pool that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. If the Utility is unsuccessful in permitting and constructing the on-site dry cask storage facility, and is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo

Canyon may have to be curtailed or halted as early as 2007 and until such time as additional spent fuel can be safely stored.

PG&E Corporation and its subsidiaries provide non-contributory defined benefit pension plans for certain employees and retirees, referred to collectively as pension benefits. PG&E Corporation and the Utility have elected that certain of the trusts underlying these plans be treated under the Internal Revenue Code as qualified trusts. If certain conditions are met, PG&E Corporation and the Utility are allowed a deduction for payments made to the qualified trusts, subject to certain Internal Revenue Code limitations. PG&E Corporation and its subsidiaries also provide contributory defined benefit medical plans for certain retired employees and their eligible dependents, and non-contributory defined benefit life insurance plans for certain retired employees (referred to collectively as other benefits). The following schedules aggregate all PG&E Corporation's and the Utility's plans. As discussed in Note 5, NEGT financial results are no longer consolidated in those of PG&E Corporation following the July 8, 2003 Chapter 11 filing of NEGT. Accordingly, pension and other benefits information is disclosed below for plans that PG&E Corporation and the Utility sponsor at December 31, 2004. PG&E Corporation and its subsidiaries use a December 31 measurement date for all of their plans.

The following reconciles changes in aggregate projected benefit obligations for pension benefits and changes in the benefit obligation of other benefits during 2004 and 2003:

	PG&E Corporation						Utility
	2004			2003			2004			2003
	(in millions)
Projected benefit obligation at January 1	$	7,516		$	6,738		$	7,509		$	6,732
Service cost for benefits earned		194			170			194			170
Interest cost		482			446			482			445
Plan amendments		28			135			28			135
Actuarial loss		667			338			667			338
Settlement		—			(4	)		—			(4	)
Benefits and expenses paid		(330	)		(307	)		(329	)		(307	)

Projected benefit obligation at December 31	$	8,557		$	7,516		$	8,551		$	7,509

Accumulated benefit obligation	$	7,638		$	6,656		$	7,632		$	6,650

PG&E Corporation has participants in the Utility's Retirement Plan, Retirement Excess Benefit Plan and the Supplemental Executive Retirement Plan. PG&E Corporation's obligation for its participants in these plans was approximately $19 million at December 31, 2004 and $15 million at December 31, 2003, and is recorded as a liability in PG&E Corporation's Balance Sheets.

	PG&E Corporation						Utility
	2004			2003			2004			2003
	(in millions)
Benefit obligation at January 1	$	1,444		$	1,197		$	1,444		$	1,197
Service cost for benefits earned		32			29			32			29
Interest cost		85			79			85			79
Actuarial loss		(103	)		61			(103	)		61
Participants paid benefits		30			33			30			33
Plan amendments		—			124			—			124
Benefits paid		(89	)		(79	)		(89	)		(79	)

Benefit obligation at December 31	$	1,399		$	1,444		$	1,399		$	1,444

PG&E Corporation has participants in the Utility's Postretirement Medical Plan and Postretirement Life Insurance Plan. PG&E Corporation's obligation for its participants in these plans was approximately $1 million at December 31, 2004 and $1 million at December 31, 2003, and is recorded as a liability in PG&E Corporation's Balance Sheets.

PG&E Corporation and the Utility use publicly quoted market values and independent pricing services depending on the nature of the assets, as reported by the trustee to determine the fair value of the plan assets.

	PG&E Corporation						Utility
	2004			2003			2004			2003
	(in millions)
Fair value of plan assets at January 1	$	7,129		$	6,153		$	7,129		$	6,153
Actual return on plan assets		787			1,280			787			1,280
Company contributions		27			7			27			7
Settlement		—			(4	)		—			(4	)
Benefits and expenses paid		(329	)		(307	)		(329	)		(307	)

Fair value of plan assets at December 31	$	7,614		$	7,129		$	7,614		$	7,129

	PG&E Corporation						Utility
	2004			2003			2004			2003
	(in millions)
Fair value of plan assets at January 1	$	955		$	749		$	955		$	749
Actual return on plan assets		108			186			108			186
Company contributions		71			72			71			72
Plan participant contribution		30			33			30			33
Benefits and expenses paid		(95	)		(85	)		(95	)		(85	)

Fair value of plan assets at December 31	$	1,069		$	955		$	1,069		$	955

The following schedule reconciles the plans' aggregate funded status to the prepaid or accrued benefit cost recorded on PG&E Corporation's and the Utility's Consolidated Balance Sheets. The funded status is the difference between the fair value of plan assets and projected benefit obligations.

	PG&E Corporation						Utility
	December 31,						December 31,
	2004			2003			2004			2003
	(in millions)
Fair value of plan assets at December 31	$	7,614		$	7,129		$	7,614		$	7,129
Projected benefit obligation at December 31		(8,557	)		(7,516	)		(8,551	)		(7,509	)

Funded status plan assets less than projected benefit obligation		(943	)		(387	)		(937	)		(380	)
Unrecognized prior service cost		378			405			378			405
Unrecognized net loss		1,148			715			1,148			714
Unrecognized net transition obligation		2			8			2			8

Prepaid (accrued) benefit cost	$	585		$	741		$	591		$	747

Prepaid benefit cost	$	638		$	792		$	638		$	792
Accrued benefit liability		(53	)		(51	)		(47	)		(45	)
Additional minimum liability		—			(7	)		—			(7	)
Intangible asset		—			—			—			—
Accumulated other comprehensive income		—			7			—			7

Prepaid (accrued) benefit cost	$	585		$	741		$	591		$	747

	PG&E Corporation						Utility
	December 31,						December 31,
	2004			2003			2004			2003
	(in millions)
Fair value of plan assets at December 31	$	1,069		$	955		$	1,069		$	955
Benefit obligation at December 31		(1,399	)		(1,444	)		(1,399	)		(1,444	)

Funded status plan assets less than benefit obligation		(330	)		(489	)		(330	)		(489	)
Unrecognized prior service cost		110			125			110			125
Unrecognized net loss		1			125			1			125
Unrecognized net transition obligation		205			232			205			232

Prepaid (accrued) benefit cost	$	(14	)	$	(7	)	$	(14	)	$	(7	)

Prepaid benefit cost	$	—		$	—		$	—		$	—
Accrued benefit liability		(14	)		(7	)		(14	)		(7	)
Additional minimum liability		—			—			—			—

Prepaid (accrued) benefit cost	$	(14	)	$	(7	)	$	(14	)	$	(7	)

The separate prepaid benefit costs and accrued benefit liabilities of PG&E Corporation's pension and other benefit plans were as follows:

		PG&E Corporation						Utility
		December 31,						December 31,
		2004			2003			2004			2003
		(in millions)
Pension Benefits:
	Prepaid benefit cost	$	638		$	792		$	638		$	792
	Accrued benefit liabilities		(53	)		(51	)		(47	)		(45	)
Other Benefits:
	Prepaid benefit cost	$	—		$	—		$	—		$	—
	Accrued benefit liabilities		(14	)		(7	)		(14	)		(7	)

The aggregate projected benefit obligation, accumulated benefit obligation and fair value of plan assets for plans in which the fair value of plan assets are less than either the projected benefit obligation or accumulated benefit obligation as of December 31, 2004 and 2003 were as follows:

		Pension Benefits						Other Benefits
		2004			2003			2004			2003
		(in millions)
PG&E Corporation:
	Projected benefit obligation	$	(8,557	)	$	(7,516	)	$	(1,399	)	$	(1,444	)
	Accumulated benefit obligation		(7,638	)		(6,656	)		—			—
	Fair value of plan assets		7,614			7,129			1,069			955
Utility:
	Projected benefit obligation	$	(8,551	)	$	(7,509	)	$	(1,399	)	$	(1,444	)
	Accumulated benefit obligation		(7,632	)		(6,650	)		—			—
	Fair value of plan assets		7,614			7,129			1,069			955

The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic cost. Weighted average, year-end assumptions were used in determining the plans' projected benefit obligations, while prior year-end assumptions are used to compute net benefit cost.

The assumed health care cost trend rate for 2005 is approximately 10%, grading down to an ultimate rate in 2009 and beyond of approximately 5.0%. A one-percentage point change in assumed health care cost trend rate would have the following effects:

The difference between actual and expected return on plan assets is included in net amortization and deferral, and is considered in the determination of future net benefit income (cost). The actual return on plan assets was above the expected return in 2004 and 2003, and below the expected return in 2002.

Under SFAS No. 71, regulatory adjustments have been recorded in the Consolidated Statements of Operations and Consolidated Balance Sheets of the Utility to reflect the difference between Utility pension expense or income for accounting purposes and Utility pension expense or income for ratemaking, which is based on a funding approach. The CPUC has authorized the Utility to recover the costs associated with its other benefits for 1993 and beyond. Recovery is based on the lesser of the amounts collected in rates or the annual contributions on a tax-deductible basis to the appropriate trusts.

The asset allocation of PG&E Corporation's and the Utility's pension and other benefit plans at December 31, 2004 and 2003, and target 2005 allocation was as follows:

Equity securities include a small amount (less than 0.1% of total plan assets) of PG&E Corporation common stock.

The maturity of debt securities at December 31, 2004 and 2003 ranges from zero to 45 years, with a weighted average maturity of approximately 6.32 years.

PG&E Corporation's and the Utility's investment strategy for all plans is to maintain actual asset weightings within 5% of the target asset allocations. Whenever the actual weighting exceeds the target weighting by 5%, the asset holdings are rebalanced.

A benchmark portfolio for each asset class is set based on market capitalization and valuations of equities and the durations and credit quality of debt securities. Investment managers for each asset

class are retained to periodically adjust, or actively manage, the combined portfolio against the benchmark. Active management covers approximately 70% of the U.S. equity, 60% of the non-U.S. equity, and virtually 100% of the debt security portfolios.

PG&E Corporation and the Utility expect to contribute approximately $20 million to its Pension Benefits Plan, to fund voluntary retirement program obligations and approximately $65 million to its Other Benefits plans in 2005. These contributions would be consistent with PG&E Corporation's and the Utility's funding policy, which is to contribute amounts that are tax deductible, consistent with applicable regulatory decisions and sufficient to meet minimum funding requirements. None of these benefit plans are subject to a minimum funding requirement in 2005.

The estimated benefits expected to be paid in each of the next five fiscal years and in aggregate for the five fiscal years thereafter are as follows:

	PG&E Corporation		Utility
	(in millions)
Pension
2005	$	349	$	349
2006		369		368
2007		389		389
2008		412		411
2009		437		436
2010-2015		2,584		2,581
Other benefits
2005	$	55	$	55
2006		65		65
2007		76		76
2008		86		86
2009		96		96
2010-2015		651		651

PG&E Corporation and its subsidiaries also sponsor defined contribution pension plans. These plans are qualified under applicable sections of the Internal Revenue Code. These plans provide for tax-deferred salary deductions and after-tax employee contributions as well as employer contributions. Employees designate the funds in which their contributions and any employer contributions are invested. Employer contributions include matching of up to 5% of an employee's base compensation and/or basic contributions of up to 5% of an employee's base compensation. Matching employer contributions are automatically invested in PG&E Corporation common stock. Employees may reallocate matching employer contributions and accumulated earnings thereon to another investment fund or funds available to the plan at any time after they have been credited to their account.

Employer contribution expense reflected in PG&E Corporation's Consolidated Statements of Operations amounted to:

PG&E Corporation maintains a long-term incentive program, or LTIP, that permits stock options, restricted stock and other stock-based incentive awards to be granted to non-employee directors, executive officers and other employees of PG&E Corporation and its subsidiaries. Stock options can be granted with or without associated stock appreciation rights and dividend equivalents.

At December 31, 2004, 31,489,783 shares of PG&E Corporation common stock were authorized for award under the LTIP, of which 10,439,785 shares were available for grant.

The weighted average grant date fair values of options granted using the Black-Scholes valuation method were $8.70 per share in 2004, $7.27 per share in 2003, and $6.61 per share in 2002. Significant assumptions used in the Black-Scholes valuation method for shares granted in 2004, 2003, and 2002 were:

	2004	2003	2002
Expected stock price volatility	45.0%	45.0%	30%
Expected annual dividend payment	$1.20	$—	$—
Risk-free interest rate	3.66%	3.46%	4.65%
Expected life	6.5 years	6.5 years	10 years

Stock options issued after January 2003 become exercisable on a cumulative basis at one-fourth each year commencing one year from the date of the grant. Stock options issued before January 2003 become exercisable on a cumulative basis at one-third each year commencing two years from the date of grant. All options expire ten years and one day after the date of grant. Options outstanding at December 31, 2004, had option prices ranging from $12.50 to $33.50, and a weighted average remaining contractual life of 5.60 years.

The following table summarizes stock option activity for the years ended December 31:

The following summarizes information for options outstanding and exercisable at December 31, 2004. Of the outstanding options at December 31, 2004:

In addition, 1,420,000 options were granted on January 3, 2005, at an exercise price of $33.02, the then-current market price of PG&E Corporation common stock.

Stock options outstanding to purchase PG&E Corporation common stock held by Utility employees at December 31, 2004 had option prices ranging from $12.63 to $33.50, and a weighted average remaining contractual life of 5.81 years. The following table summarizes the stock option activity for the Utility employees for the years ended December 31:

The following summarizes information for options outstanding and exercisable at December 31, 2004. Of the outstanding options at December 31, 2004:

In addition, 1,042,550 options were granted to Utility employees on January 3, 2005 at an exercise price of $33.02, the then-current market price of PG&E Corporation common stock.

At December 31, 2004, a total of 2,088,920 shares of restricted PG&E Corporation common stock had been awarded to eligible employees of PG&E Corporation and its subsidiaries, of which 1,351,675 shares were granted to Utility employees. PG&E Corporation granted 498,910 shares of restricted common stock during 2004, of which 342,180 shares were granted to Utility employees. At December 31, 2004, 1,601,710 shares of restricted PG&E Corporation common stock were outstanding, of which 1,056,610 related to Utility employees. The shares were granted with restrictions and are subject to forfeiture unless certain conditions are met.

The restricted shares are held in an escrow account. The shares become available to the employees as the restrictions lapse. For restricted stock granted in 2003, the restrictions on 80% of the shares lapse automatically over a period of four years at the rate of 20% per year. The compensation expense for these shares remains fixed at the value of the stock at grant date. Restrictions on the remaining 20% of the shares will lapse at a rate of 5% per year if PG&E Corporation is in the top quartile of its comparator group as measured by annual total shareholder return for each year ending immediately before each annual lapse date. The compensation expense recognized for these shares is variable, and changes with the common stock's market price. The performance criteria during 2004 was not met. For restricted stock grants awarded in 2004, there were no restricted stock shares containing performance criteria and the restrictions lapse ratably over four years.

Compensation expense associated with all the shares is recognized on a quarterly basis, by amortizing the unearned compensation related to that period. Total compensation expense resulting from the restricted stock issuance reflected on PG&E Corporation's Consolidated Statements of Operations was approximately $9 million in 2004 and approximately $7 million in 2003, of which approximately $6 million in 2004 and approximately $4 million in 2003 was recognized by the Utility. The total unamortized balance of unearned compensation resulting from the restricted stock issuance reflected on PG&E Corporation's Consolidated Balance Sheets was approximately $26 million at December 31, 2004 and $20 million at December 31, 2003. On January 3, 2005 PG&E Corporation awarded 328,340 shares of restricted stock, of which 241,240 shares were granted to Utility employees.

Starting in 2004, PG&E Corporation awarded 498,910 performance shares, or phantom stock, to certain officers and employees of PG&E Corporation and its subsidiaries of which 342,180 were awarded to Utility employees. The performance shares, subject to the achievement of certain performance targets, vest on the third year anniversary following the date of the grant. The number of

performance shares that were outstanding at December 31, 2004 was 486,010 of which 330,832 were related to Utility employees. The amount of compensation expense recognized in 2004 in connection with the issuance of performance shares was approximately $3 million, of which $2 million was recognized by the Utility. On January 3, 2005, PG&E Corporation awarded 328,340 performance shares, of which 241,240 were awarded to Utility employees.

PG&E Corporation has granted performance units to certain officers and employees of PG&E Corporation and its subsidiaries. The performance units, subject to achievement of certain performance targets, vest one-third per year and are settled in cash annually as vesting occurs in each of the three years following the year of grant. As a result of achieving performance criteria, at December 31, 2004, all remaining units vested and PG&E Corporation recognized compensation expense totaling approximately $5 million in 2004, of which $2 million related to the Utility. These amounts were paid in January 2005 to the participating individuals.

The supplemental retirement savings plan provides supplemental retirement alternatives to eligible officers and key employees of PG&E Corporation and its subsidiaries by allowing participants to defer portions of their compensation, including salaries and amounts awarded under various incentive awards and to receive supplemental employer-provided retirement benefits. Under the employee-elected deferral component of the plan, eligible employees may defer all or part of their incentive awards, and 5% to 50% of their salary. Under the supplemental employer-provided retirement benefits component of the plan, eligible employees may receive full credit for employer matching and basic contributions, under the respective defined contribution plan, in excess of limitations set out by the Internal Revenue Code. A separate non-qualified account is maintained for each eligible employee to track deferred amounts. The account's value is adjusted in accordance with the performance of the investment options selected by the employee. Each employee's account is adjusted on a quarterly basis and the change in value is recorded as additional compensation expense or income in the Consolidated Financial Statements. Total compensation expense recognized by PG&E Corporation and the Utility in connection with the plan amounted to:

PG&E Corporation implemented various retention programs in 2001. One of these programs granted key personnel of PG&E Corporation and its subsidiaries with lump-sum cash payments. In addition, another program granted units of special senior executive retention grants.

These grants provided certain employees with PG&E Corporation phantom restricted stock units that vested in full on December 31, 2003 upon PG&E Corporation meeting certain performance measures at that date. A total of 3,044,600 phantom stock units were granted under this program. There were no similar grants in 2004. These units were marked to market based on the market price of PG&E Corporation common stock and amortized as a charge to income over a four-year period. As a result of meeting the performance criteria at December 31, 2003, these units fully vested and the remaining compensation expense was recognized in 2003. Total compensation expense recognized in

connection with these retention mechanisms, including cash payments and phantom restricted stock units, amounted to:

In January 2004, approximately $84.5 million was paid to participating individuals in the senior executive retention program. There are no payments remaining under either plan.

The significant components of income tax (benefit) expense for continuing operations were:

The differences between income taxes and amounts calculated by applying the federal legal rate to income before income tax expense for continuing operations were:

The IRS has completed its audit of PG&E Corporation's 1997 and 1998 consolidated federal income tax returns and has assessed additional federal income taxes of approximately $79 million (including interest). PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and currently is discussing these adjustments with the IRS Appeals Office. PG&E Corporation does not expect final resolution of these appeals to have a material impact on its financial position or results of operations.

All IRS audits of PG&E Corporation's federal income tax returns prior to 1997 have been closed.

Prior to July 8, 2003, the date that NEGT filed for bankruptcy protection, PG&E Corporation recognized federal income tax benefits related to the losses of NEGT and its subsidiaries. However, after July 7, 2003, PG&E Corporation has not recognized additional income tax benefits for financial reporting purposes with respect to the losses of NEGT and its subsidiaries even though it must continue to include NEGT and its subsidiaries in its consolidated income tax returns. As a result of NEGT's plan of reorganization becoming effective on October 29, 2004, PG&E Corporation cancelled its equity interest in NEGT and no longer includes NEGT or its subsidiaries in its consolidated income tax returns. Remaining deferred tax assets related to NEGT or its subsidiaries, were reversed in discontinued operations in the Consolidated Statements of Operations at the time PG&E Corporation's equity interest in NEGT was cancelled. See Note 5 for further discussion.

In 2003, PG&E Corporation increased its valuation allowance due to the uncertainty in realizing certain state deferred tax assets related to NEGT or its subsidiaries. Valuation allowances of approximately $24 million were recorded in discontinued operations, and approximately $5 million in accumulated other comprehensive loss for the year ended December 31, 2003. No valuation allowances were recorded during 2004.

At December 31, 2003, PG&E Corporation had $420 million of California net operating loss, or NOL. The California NOLs were fully utilized in 2004.

PG&E Corporation and the Utility have substantial financial commitments and contingencies in connection with agreements entered into supporting the Utility's operating activities. PG&E Corporation has no ongoing financial commitments relating to NEGT's current operating activities.

PG&E Corporation has previously agreed to accept the assignment of certain Canadian natural gas pipeline firm transportation contracts effective November 1, 2007, through October 31, 2023, the remaining term of the contracts' duration. The firm quantity under the contracts is approximately 50 million cubic feet per day, or MMcf/d, and PG&E Corporation has estimated annual reservation charges will range between approximately $10 million and $12 million. During the term of the contracts, the applicable reservation charges will equal the full tariff rates set by regulatory authorities in Canada and the United States, as applicable. PG&E Corporation is unable to predict the utilization of these contracts, which will depend on market prices, customer demand, and approval of cost recovery by the CPUC, among other factors. PG&E Corporation intends to assign these contracts to the Utility.

power purchase agreements with existing qualifying facilities with expiring power purchase agreements and with newly-constructed qualifying facilities. PG&E Corporation and the Utility are unable to estimate the outcome of these proceedings.

Annual Receipts and Payments—The payments made under qualifying facility, irrigation district, water agency and bilateral agreements during 2002 through 2004 were as follows:

	2004		2003		2002
Qualifying facility energy payments (in millions)	$	1,002	$	994	$	1,051
Qualifying facility capacity payments (in millions)	$	487	$	499	$	506
Irrigation district and water agency payments (in millions)	$	61	$	62	$	57
Other power purchase agreement payments (in millions)	$	834	$	513	$	196

At December 31, 2004, the undiscounted future expected power purchase agreement payments were as follows:

At December 31, 2004, the Utility's obligations for natural gas purchases and gas transportation services were as follows:

Payments for natural gas purchases and gas transportation services amounted to approximately $1.8 billion in 2004, $1.5 billion in 2003, and $898 million in 2002.

At December 31, 2004, the undiscounted obligations under nuclear fuel agreements were as follows:

Payments for nuclear fuel amounted to approximately $119 million in 2004, $57 million in 2003 and $70 million in 2002.

In June 2000, a FERC administrative law judge, or ALJ, issued an initial decision addressing subsidiaries of Mirant Corporation. The decision approved rates and a ratemaking methodology that, if affirmed by the FERC, will require the Mirant subsidiaries that are parties to three RMR agreements with the ISO to refund to the ISO, and the ISO to refund to the Utility, excess payments of approximately $360 million, including interest, for the availability of Mirant's RMR plants under these agreements. On July 14, 2003, Mirant filed a petition for reorganization under Chapter 11 and on December 15, 2003, the Utility filed claims in Mirant's Chapter 11 proceeding including a claim for an RMR refund. On January 14, 2005, the Utility entered into a settlement with Mirant and its subsidiaries that own RMR units that will resolve the Utility's claim. The settlement agreement is subject to approval by the FERC, the bankruptcy court overseeing the Chapter 11 cases filed by Mirant and these subsidiaries, and to the extent deemed necessary by the Utility, by the bankruptcy court that retains jurisdiction over the Utility's Chapter 11 case. Under the settlement, Mirant will transfer to the Utility Mirant's interest in and equipment for the partially built Contra Costa Unit 8 power plant. If Contra Costa Unit 8 is not transferred to the Utility as a result of various contingencies described in the settlement, Mirant will pay the Utility at least $70 million in lieu of the plant assets. In addition, under the settlement, the Utility will enter into a contract that gives the Utility the right to dispatch

power from certain RMR units owned by Mirant subsidiaries from 2006-2012, and the Utility will receive approximately $60 million of allowed claims, credits, offsets, or cash from Mirant or its subsidiaries. The Utility is unable to predict whether and when the FERC or the bankruptcy courts will approve the settlement. Although the settlement resolves issues concerning any refund that might be owed by Mirant, it does not address the underlying merits of the RMR case, which will still be decided by the FERC.

Payments for other commitments amounted to approximately $111 million in 2004, $74 million in 2003, and $34 million in 2002.

PG&E Corporation retains a guarantee related to certain NEGT indemnity obligations issued to the purchaser of an NEGT subsidiary company during 2000, up to $150 million. The underlying indemnity obligations of NEGT have expired and PG&E Corporation's sole remaining exposure relates to the potential of environmental obligations that were known to NEGT at the time of the sale but not disclosed to the purchaser. PG&E Corporation has never received any claims nor does it consider it probable any claims will occur under the guarantee. Accordingly, PG&E Corporation has made no provision for this guarantee at December 31, 2004.

The Utility had PX block-forward contracts, which were seized by California's then-Governor Gray Davis in February 2001 for the benefit of the state, acting under California's Emergency Services Act. The block-forward contracts had an estimated unrealized gain of up to $243 million at the time the state of California seized them. The Utility, the PX, and some of the PX market participants have filed claims in state court against the state of California to recover the value of the seized contracts; the state of California disputes the plaintiffs' rights to recover and valuations. The estimated value of the seized contracts has been fully reserved in the Utility's financial statements. This state court litigation is pending.

The Utility has entered into settlements with various power suppliers resolving the Utility's claims against these power suppliers. As discussed in Note 1, as of December 31, 2004, the Utility has recorded offsets to the Settlement Regulatory Asset of approximately $309 million, pre-tax ($183 million, after-tax) in connection with settlements. The final net after-tax amount of any amounts received by the Utility under future settlements with energy suppliers will be credited to customers, either as a reduction to the principal amount of the second series of ERBs, anticipated to be issued in November 2005, or if refunds are received after the second series of ERBs is issued, as a credit to the balancing account that tracks recovery of the customer costs and benefits related to the ERBs.

As discussed in Note 13 below, in January 2005, the Utility and other parties entered into a settlement agreement with Mirant Corporation and its subsidiaries, to resolve Mirant's liability for FERC refunds, penalties and civil liabilities arising out of the California energy crisis. The settlement agreement is subject to approval by the FERC, the bankruptcy court overseeing Mirant's bankruptcy proceedings, and to the extent deemed necessary by the Utility, the bankruptcy court that retains jurisdiction over the Utility's Chapter 11 case. Although settlement discussions with a number of other major sellers and other market participants are continuing, the Utility cannot predict whether these settlement negotiations will be successful.

The Utility has several types of nuclear insurance for Diablo Canyon and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited, or NEIL. NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $42.5 million per one-year policy term.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of domestic terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member within a 12-month period, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion plus the additional amounts recovered by NEIL for these losses from reinsurance. Under the Terrorism Risk Insurance Act of 2002, NEIL would be entitled to receive substantial proceeds from reinsurance coverage for an act caused by foreign terrorism. The Terrorism Risk Insurance Act of 2002 expires on December 31, 2005.

Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $10.8 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for Diablo Canyon. The balance of the $10.8 billion of liability protection is covered by a loss-sharing program (secondary financial protection) among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of nuclear reactors that are licensed to operate, designed for the production of electrical energy, and have a rated capacity of 100 MW or higher. If a nuclear incident results in costs

in excess of $300 million, then the Utility may be responsible for up to $100.6 million per reactor, with payments in each year limited to a maximum of $10 million per incident until the Utility has fully paid its share of the liability. Since Diablo Canyon has two nuclear reactors each with a rated capacity of over 100 MW, the Utility may be assessed up to $201.2 million per incident, with payments in each year limited to a maximum of $20 million per incident. Although the Price-Anderson Act expired on December 31, 2003, coverage continues to be provided to all licensees, including Diablo Canyon, which had coverage before December 31, 2003. Congress may address renewal of the Price-Anderson Act in future energy legislation.

In addition, the Utility has $53.3 million of liability insurance for the retired nuclear generating unit at Humboldt Bay power plant and has a $500 million indemnification from the NRC, for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of liability insurance.

The Utility is self-insured for workers' compensation. To maintain its status as a self-insurer for workers' compensation, the Utility must either deposit collateral with the California Department of Industrial Relations, or the DIR, or participate in the Alternative Security Deposit program, or the ASP, which is administered by the Self-Insurer's Security Fund, or the SISF. The ASP is a program that allows the SISF to arrange a composite deposit for participating self-insurers on a portfolio basis, rather than individual self-insurers arranging their deposits individually. The SISF arranges portfolio security to be delivered to the DIR for the aggregate self-insured workers' compensation liabilities for participating self-insurers. The SISF composite deposit for participating self-insurers, including the Utility, was established on July 1, 2004, and resulted in the release of the $348 million collateral ($305 million in surety bonds and $43 million in cash) that existed at June 30, 2004. As a result, PG&E Corporation's guarantee of the Utility's reimbursement obligation associated with these surety bonds was reduced by $305 million, and the remaining liability is expected to be immaterial.

PG&E Corporation's guarantee of the Utility's underlying obligation to pay workers' compensation claims remains in place. As of December 31, 2004, the actuarially determined workers' compensation liability was approximately $226 million.

The DWR provided approximately 25% of the electricity delivered to the Utility's customers for the year ended December 31, 2004. The DWR purchased the electricity under contracts with various generators. The Utility is responsible for administration and dispatch of the DWR's electricity procurement contracts allocated to the Utility for purposes of meeting a portion of the Utility's net open position, which is the portion of the demand of a utility's customers, plus applicable reserve margins, not satisfied from that utility's own generation facilities and existing electricity contracts. The DWR remains legally and financially responsible for the electricity procurement contracts.

The current DWR contracts terminate at various times through 2012, and consist of must-take and capacity charge contracts. Under must-take contracts, the DWR must take and pay for electricity generated by the applicable generating facility regardless of whether the electricity is needed. Under capacity charge contracts, the DWR must pay a capacity charge but is not required to purchase electricity unless that electricity is dispatched and delivered. In the Utility's proposed long-term integrated energy resource plan filed with the CPUC in July 2004 and approved in December 2004, the Utility has not assumed that the electricity provided under DWR contracts will be renewed beyond their current expiration dates.

The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible.

However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. The Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:

The Utility may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under the Comprehensive Environmental Response Compensation and Liability Act of 1980, or CERCLA, as amended, and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if the Utility did not deposit those substances on the site.

The cost of environmental remediation is difficult to estimate. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can estimate a range of reasonably likely clean-up costs. The Utility reviews its remediation liability on a quarterly basis for each site where it may be exposed to remediation responsibilities. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring and site closure using current technology, enacted laws and regulations, experience gained at similar sites, and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the costs at the lower end of this range. It is reasonably possible that a change in these estimates may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper end of the cost range using reasonably possible outcomes least favorable to the Utility.

The Utility had an undiscounted environmental remediation liability of approximately $327 million at December 31, 2004, and approximately $314 million at December 31, 2003. During the year ended December 31, 2004, the liability increased by approximately $13 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The approximately $327 million accrued at December 31, 2004, includes approximately $102 million related to the pre-closing remediation liability associated with divested generation facilities and approximately $225 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, compressor stations, third-party disposal sites, and manufactured gas plant sites that either are owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas plant sites. Of the approximately $327 million environmental remediation liability, approximately $144 million has been included in prior rate setting proceedings and the Utility expects that approximately $141 million will be allowable for inclusion in future rates. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refund to customers.

The Utility's undiscounted future costs could increase to as much as $480 million if the other potentially responsible parties are not financially able to contribute to these costs, or if the extent of contamination or necessary remediation is greater than anticipated. The amount of approximately $480 million does not include an estimate for the cost of remediation at known sites owned or operated in the past by the Utility's predecessor corporations for which the Utility has not been able to determine whether a liability exists.

In the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. The most significant of these are discussed below. On the Effective Date, the automatic stay of pending litigation was lifted, so that any state court lawsuits pending before the Utility's Chapter 11 filing that had not yet received relief from the stay can proceed.

There are 14 civil suits pending against the Utility in several California state courts in which plaintiffs allege that exposure to chromium at or near the Utility's compressor stations at Hinkley and Kettleman, California, and the area of California near Topock, Arizona, caused personal injuries, wrongful deaths, or other injury and seek related damages. One of these suits also names PG&E Corporation as a defendant. Currently, there are approximately 1,200 plaintiffs in the chromium litigation cases. Approximately 1,260 individuals filed proofs of claims in the Utility's Chapter 11 case, most of whom also are plaintiffs in the chromium litigation cases. Approximately 1,035 of these claimants filed claims requesting an approximate aggregate amount of $580 million and approximately another 225 claimants filed claims for an "unknown amount." Pursuant to the Utility's plan of reorganization, these claims have passed through the Utility's Chapter 11 proceeding unimpaired.

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

To assist in managing and resolving litigation with this many plaintiffs, the parties agreed to select plaintiffs from three of the cases for a test trial. Plaintiffs' counsel selected ten of these initial trial plaintiffs, defense counsel selected seven of the initial trial plaintiffs, and one plaintiff and two alternates were selected at random. The Utility has filed 14 motions challenging the test trial plaintiffs' lack of admissible scientific evidence that chromium caused the alleged injuries. The court began hearing argument on two of the motions in February 2004. At a hearing on February 14, 2005, the court indicated that it had signed orders denying the first two motions, but the orders have not been delivered to the parties. The court set a trial date of January 9, 2006 for the first eighteen plaintiffs. The other motions will be heard throughout 2005.

The Utility has recorded a $160 million reserve in its financial statements with respect to the chromium litigation. PG&E Corporation and the Utility believe that, after taking into account the reserves recorded at December 31, 2004, the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation's or the Utility's financial condition or future results of operations.

In accordance with SFAS No. 5, PG&E Corporation and the Utility make a provision for a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed quarterly and adjusted to reflect the impacts of negotiations, settlements and payments, rulings, advice of legal counsel and other information and events pertaining

to a particular case. In assessing such contingencies, PG&E Corporation's and the Utility's policy is to exclude anticipated legal costs.

The liability for legal matters is included in PG&E Corporation's and the Utility's other noncurrent liabilities in the Consolidated Balance Sheets, and totaled approximately $200 million at December 31, 2004 and $205 million at December 31, 2003. Based on current information, PG&E Corporation and the Utility do not believe that it is probable that losses associated with legal matters that exceed amounts already recognized will be incurred in amounts that would be material to PG&E Corporation's or the Utility's financial position or results of operations.

In connection with the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the remaining unamortized portion of the Settlement Regulatory Asset and associated federal and state income and franchise taxes, in an aggregate principal amount of up to $3.0 billion in two separate series up to one year apart, as expeditiously as practicable after the Effective Date using a securitized financing supported by a DRC provided that certain conditions were met. On February 10, 2005, PERF, a limited liability company wholly owned and consolidated by the Utility, issued $1.9 billion of ERBs. The proceeds of the ERBs were used by PERF to purchase from the Utility the right, known as "recovery property," to be paid a specified amount from a DRC. DRC charges are authorized by the CPUC under state legislation and will be paid by the Utility's electricity customers until the ERBs are fully retired. Under the terms of a recovery property servicing agreement, DRC charges are collected by the Utility and remitted to PERF.

The aggregate principal amount of the first series of ERBs issued is approximately $1.9 billion. They were issued in five classes, with scheduled maturities ranging from September 25, 2006 to December 25, 2012, and final legal maturities ranging from September 25, 2008 to December 25, 2014. Interest rates on the five classes range from 3.32% for the earliest maturing class to 4.47% for the latest maturing class.

While PERF is a wholly owned consolidated subsidiary of the Utility, PERF is legally separate from the Utility. The assets of PERF (including the recovery property) are not available to creditors of PG&E Corporation or the Utility and the recovery property is not legally an asset of the Utility or PG&E Corporation.

In January 2005, the Utility entered into a settlement agreement with Mirant Corporation and several of its subsidiaries, resolving overcharges and market manipulation claims from the sale of electricity by Mirant's California operations.

The first part of the two-part settlement is between Mirant and several California parties, including the California Attorney General's Office, the DWR, the CPUC, SCE, San Diego Gas & Electric Company, or the California Parties, and the Utility resolving market manipulation claims, including Mirant's liability for FERC refunds, penalties and civil liabilities arising out of the California energy crisis in 2000 to 2001. Under this portion of the agreement, Mirant will provide the California Parties approximately $320 million in cash equivalents and $175 million of allowed bankruptcy claims. Of these amounts, the Utility will receive approximately $130 million in cash equivalents and $40 million in allowed claims. The final cash value of the allowed claims will not be known until the completion of Mirant's bankruptcy proceeding. The Utility's net after-tax refund amount will benefit its customers through adjustment of future revenue requirements.

The second part of the settlement is between the Utility and Mirant and is designed to settle claims that Mirant overcharged the Utility under Mirant's RMR contracts and other disputes. Under the settlement agreement, Mirant has agreed to transfer to the Utility the equipment, permits and contracts for the construction of Contra Costa Unit 8, a modern 530-megawatt power plant Mirant started to build, but never completed. The Utility plans to file an application with the CPUC to seek authorization to complete and operate Contra Costa Unit 8 under a cost-of-service ratemaking structure. If the Utility and Mirant do not complete the necessary transfer agreement or if the Utility does not receive the necessary approvals, including CPUC authorization, the Utility will be paid at least $70 million in lieu of transferring the assets. The settlement agreement also includes a contract that would give the Utility the right from 2006 through 2012 to dispatch power from certain RMR units owned by Mirant subsidiaries when the facilities are not needed by the ISO to meet local reliability needs. In addition, the Utility will receive approximately $60 million of allowed claims, credits, offsets, and/or cash from Mirant Corporation or its subsidiaries and Mirant will withdraw its outstanding claim in the Utility's bankruptcy proceeding of approximately $20 million. The settlement may also include separate options under which the Utility, under certain circumstances, would have the right to acquire Mirant's existing Contra Costa and Pittsburg power plants.

The settlement agreement is not effective until it is approved by the FERC, the bankruptcy court overseeing Mirant's bankruptcy proceedings and, to the extent deemed necessary by the Utility, the bankruptcy court that retains jurisdiction over the Utility's Chapter 11 case. PG&E Corporation and the Utility are unable to predict whether and when the settlement agreement will be approved.

Management of PG&E Corporation and Pacific Gas and Electric Company, or the Utility, is responsible for establishing and maintaining adequate internal control over financial reporting. PG&E Corporation's and the Utility's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, or GAAP. Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of PG&E Corporation and the Utility, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that receipts and expenditures are being made only in accordance with authorizations of management and directors of PG&E Corporation and the Utility, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

The Consolidated Financial Statements of PG&E Corporation and the Utility include the accounts of an entity consolidated pursuant to Financial Accounting Standards Board Interpretation No. 46R, or FIN 46R. Management's responsibility for and assessment of the effectiveness of internal control over financial reporting does not extend to this entity because management has been unable to assess the effectiveness of internal control at this entity due to the fact that PG&E Corporation and the Utility do not have the ability to dictate or modify the controls of this entity and do not have the ability, in practice, to assess those controls. PG&E Corporation's and the Utility's Consolidated Balance Sheets include an increase of $12 million in total assets and total liabilities as a result of the consolidation of a low-income housing partnership consolidated under FIN 46R.

Management assessed the effectiveness of internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment and those criteria, management has concluded that PG&E Corporation and the Utility maintained effective internal control over financial reporting as of December 31, 2004.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited the Consolidated Financial Statements of PG&E Corporation and the Utility for the three years ended December 31, 2004, appearing in this annual report and has issued an attestation report on management's assessment of internal control over financial reporting, as stated in their report, which is included in this annual report on page 145.

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 and subsidiaries (the "Utility") as of December 31, 2004 and 2003, and the related consolidated statements of operations, cash flows and shareholders' equity of the Company and of the Utility for each of the three years in the period ended December 31, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). 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, 2004 and 2003, and the respective results of their consolidated operations and cash flows for each of the three years in the period ended December 31, 2004, 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, in March 2004, the Company changed the method of computing earnings per share. During 2003, the Company and the Utility adopted new accounting standards to account for asset retirement obligations and financial instruments with characteristics of both liabilities and equity. During 2002, the Company adopted new accounting standards to account for goodwill and intangible assets, impairment of long-lived assets and certain derivative contracts.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's and the Utility's internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 16, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

To the Boards of Directors and Shareholders of
PG&E Corporation and Pacific Gas and Electric Company

We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that PG&E Corporation and subsidiaries (the "Company") and Pacific Gas and Electric Company and subsidiaries (the "Utility") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management's Report on Internal Control Over Financial Reporting, management excluded from their assessment the internal control over financial reporting of an entity consolidated pursuant to Financial Accounting Standards Board Interpretation No. 46R which represents total assets and total liabilities of $12 million as of December 31, 2004. Accordingly, our audits did not include the internal control over financial reporting for this entity. The Company's and the Utility's management is responsible for maintaining effective internal control over financial reporting and for their assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's and the Utility's internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audits included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company and the Utility maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company and the Utility maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2004 of the Company and the Utility and our report dated February 16, 2005 expressed an unqualified opinion (and includes an explanatory paragraph relating to accounting changes) on those financial statements and financial statement schedules.

PG&E Corporation and Pacific Gas and Electric Company, or the Utility, management are responsible for the integrity of the accompanying Consolidated Financial Statements. The financial statements have been prepared in accordance with the 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.

	2004		2003		2002		2001		2000
	(in millions, except per share amounts)
PG&E Corporation⁽¹⁾ For the Year
Operating revenues	$	11,080	$	10,435	$	10,505	$	10,450	$	9,623
Operating income (loss)		7,118		2,343		3,954		2,613		(5,077	)
Income (loss) from continuing operations		3,820		791		1,723		1,021		(3,435	)
Earnings (loss) per common share from continuing operations, basic		9.16		1.96		4.53		2.81		(9.49	)
Earnings (loss) per common share from continuing operations, diluted		8.97		1.92		4.49		2.80		(9.49	)
Dividends declared per common share		—		—		—		—		1.20
At Year-End
Book value per common share⁽²⁾	$	20.90	$	10.16	$	8.92	$	11.91	$	8.76
Common stock price per share		33.28		27.77		13.90		19.24		20.00
Total assets		34,540		30,175		36,081		38,529		38,786
Long-term debt (excluding current portion)		7,323		3,314		3,715		3,923		3,346
Rate reduction bonds (excluding current portion)		580		870		1,160		1,450		1,740
Financial debt subject to compromise		—		5,603		5,605		5,651		—
Preferred stock of subsidiary with mandatory redemption provisions		122		137		137		137		137
Pacific Gas and Electric Company⁽¹⁾ For the Year
Operating revenues	$	11,080	$	10,438	$	10,514	$	10,462	$	9,637
Operating income (loss)		7,144		2,339		3,913		2,478		(5,201	)
Income available for (loss allocated to) common stock		3,961		901		1,794		990		(3,508	)
At Year-End
Total assets	$	34,302	$	29,066	$	27,593	$	28,105	$	24,622
Long-term debt (excluding current portion)		7,043		2,431		2,739		3,019		3,342
Rate reduction bonds (excluding current portion)		580		870		1,160		1,450		1,740
Financial debt subject to compromise		—		5,603		5,605		5,651		—
Preferred stock with mandatory redemption provisions		122		137		137		137		137

		Year ended December 31,
		2004			2003			2002
		(in millions)
Utility
Electric operating revenues		$	7,867		$	7,582		$	8,178
Natural gas operating revenues			3,213			2,856			2,336

	Total operating revenues		11,080			10,438			10,514
Cost of electricity			2,770			2,319			1,482
Cost of natural gas			1,724			1,467			954
Operating and maintenance			2,842			2,935			2,817
Recognition of regulatory assets			(4,900	)		—			—
Depreciation, amortization and decommissioning			1,494			1,218			1,193
Reorganization professional fees and expenses			6			160			155

	Total operating expenses		3,936			8,099			6,601

Operating income			7,144			2,339			3,913
Interest income			50			53			74
Interest expense			(667	)		(953	)		(988	)
Other expense, net⁽¹⁾			(5	)		(9	)		(27	)

Income before income taxes			6,522			1,430			2,972
Income tax provision			2,561			528			1,178

Income before cumulative effect of a change in accounting principle			3,961			902			1,794
Cumulative effect of a change in accounting principle			—			(1	)		—

Income available for common stock		$	3,961		$	901		$	1,794

PG&E Corporation, Eliminations and Other⁽²⁾⁽³⁾
Operating revenues		$	—		$	(3	)	$	(9	)
Operating expenses			26			(7	)		(50	)

Operating income (loss)			(26	)		4			41
Interest income			13			9			6
Interest expense			(130	)		(194	)		(236	)
Other income (expense), net⁽¹⁾			(93	)		—			77

Income (loss) before income taxes			(236	)		(181	)		(112	)
Income tax benefit			(95	)		(70	)		(41	)

Income (loss) from continuing operations			(141	)		(111	)		(71	)
Discontinued operations			684			(365	)		(2,536	)
Cumulative effect of changes in accounting principles			—			(5	)		(61	)

Net income (loss)		$	$543		$	(481	)	$	(2,668	)

Consolidated Total⁽³⁾
Operating revenues		$	11,080		$	10,435		$	10,505
Operating expenses			3,962			8,092			6,551

Operating income			7,118			2,343			3,954
Interest income			63			62			80
Interest expense			(797	)		(1,147	)		(1,224	)
Other income (expenses), net⁽¹⁾			(98	)		(9	)		50

Income before income taxes			6,286			1,249			2,860
Income tax provision			2,466			458			1,137

Income from continuing operations			3,820			791			1,723
Discontinued operations			684			(365	)		(2,536	)
Cumulative effect of changes in accounting principles			—			(6	)		(61	)

Net income (loss)		$	4,504		$	420		$	(874	)

			Year ended December 31,
			2004			2003			2002
Operating Revenues
	Electric		$	7,867		$	7,582		$	8,178
	Natural gas			3,213			2,853			2,327

		Total operating revenues		11,080			10,435			10,505
Operating Expenses
	Cost of electricity			2,770			2,309			1,447
	Cost of natural gas			1,724			1,438			895
	Operating and maintenance			2,865			2,963			2,858
	Recognition of regulatory assets			(4,900	)		—			—
	Depreciation, amortization, and decommissioning			1,497			1,222			1,196
	Reorganization professional fees and expenses			6			160			155

		Total operating expenses		3,962			8,092			6,551

Operating Income				7,118			2,343			3,954
	Reorganization interest income			8			46			71
	Interest income			55			16			9
	Interest expense			(797	)		(1,147	)		(1,224	)
	Other income (expense), net			(98	)		(9	)		50

Income Before Income Taxes				6,286			1,249			2,860
	Income tax provision			2,466			458			1,137

Income From Continuing Operations				3,820			791			1,723
Discontinued Operations
	Gain on disposal of NEGT (net of income taxes of $374 million)			684			—			—
	Loss from operations of NEGT (net of income tax benefit of $230 million in 2003 and $1,558 million in 2002)			—			(365	)		(2,536	)

Net Income (Loss) Before Cumulative Effect of Changes in Accounting Principles				4,504			426			(813	)
	Cumulative effect of changes in accounting principles of $(5) million in 2003 and $(61) million in 2002 related to discontinued operations (net of income tax benefit of $3 million in 2003 and $42 million in 2002). In 2003, $(1) million related to continuing operations (net of income tax benefit of $1 million)			—			(6	)		(61	)

Net Income (Loss)			$	4,504		$	420		$	(874	)

Weighted Average Common Shares Outstanding, Basic				398			385			371

Earnings Per Common Share from Continuing Operations, Basic			$	9.16		$	1.96		$	4.53

Net Earnings (Loss) Per Common Share, Basic			$	10.80		$	1.04		$	(2.30	)

Earnings Per Common Share from Continuing Operations, Diluted			$	8.97		$	1.92		$	4.49

Net Earnings (Loss) Per Common Share, Diluted			$	10.57		$	1.02		$	(2.27	)

			Balance at December 31,
			2004			2003
ASSETS
Current Assets
	Cash and cash equivalents		$	972		$	3,658
	Restricted cash			1,980			403
	Accounts receivable:
		Customers (net of allowance for doubtful accounts of $93 million in 2004 and $68 million in 2003)		2,085			2,424
		Related parties		—			15
		Regulatory balancing accounts		1,021			248
	Inventories:
		Gas stored underground		175			166
		Materials and supplies		129			126
	Prepaid expenses and other			46			108

		Total current assets		6,408			7,148

Property, Plant and Equipment
	Electric			21,519			20,468
	Gas			8,526			8,355
	Construction work in progress			449			379
	Other			15			20

		Total property, plant and equipment		30,509			29,222
	Accumulated depreciation			(11,520	)		(11,115	)

		Net property, plant and equipment		18,989			18,107

Other Noncurrent Assets
	Regulatory assets			6,526			2,001
	Nuclear decommissioning funds			1,629			1,478
	Other			988			1,441

		Total other noncurrent assets		9,143			4,920

TOTAL ASSETS			$	34,540		$	30,175

			Balance at December 31,
			2004			2003
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
	Short-term borrowings		$	300		$	—
	Long-term debt, classified as current			758			310
	Rate reduction bonds, classified as current			290			290
	Accounts payable:
		Trade creditors		762			657
		Disputed claims		2,142			—
		Regulatory balancing accounts		369			186
		Other		352			402
	Interest payable			461			174
	Income taxes payable			185			256
	Deferred income taxes			394			102
	Other			905			761

		Total current liabilities		6,918			3,138

Noncurrent Liabilities
	Long-term debt			7,323			3,314
	Rate reduction bonds			580			870
	Regulatory liabilities			4,035			3,979
	Asset retirement obligations			1,301			1,218
	Deferred income taxes			3,531			856
	Deferred tax credits			121			127
	Net investment in NEGT			—			1,216
	Preferred stock of subsidiary with mandatory redemption provisions (redeemable, 6.30% and 6.57%, outstanding 4,925,000 shares, due 2005-2009)			122			137
	Other			1,690			1,501

		Total noncurrent liabilities		18,703			13,218

Liabilities Subject to Compromise
	Financing debt			—			5,603
	Trade creditors			—			3,715

		Total liabilities subject to compromise		—			9,318

Commitments and Contingencies (Notes 1, 2, 5 and 12)
Preferred Stock of Subsidiaries				286			286

Preferred Stock
	Preferred stock, no par value, 80,000,000 shares, $100 par Value, 5,000,000 shares, none issued			—			—
Common Shareholders' Equity
	Common stock, no par value, authorized 800,000,000 shares, issued 417,014,431 common and 1,601,710 restricted shares in 2004 and 414,985,014 common and 1,535,268 restricted shares in 2003			6,518			6,468
	Common stock held by subsidiary, at cost, 24,665,500 shares in 2004 and 23,815,500 shares in 2003			(718	)		(690	)
	Unearned compensation			(26	)		(20	)
	Accumulated earnings (deficit)			2,863			(1,458	)
	Accumulated other comprehensive loss			(4	)		(85	)

		Total common shareholders' equity		8,633			4,215

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			$	34,540		$	30,175

			2004			2003			2002
			(in millions)
Net income			$	3,982		$	923		$	1,819
Non-cash (income) expenses:
	Depreciation, amortization and decommissioning			1,494			1,218			1,193
	Gain on establishment of regulatory asset, net			(2,904	)		—			—
	Net reversal of ISO accrual			—			—			(970	)
Change in accounts receivable				(85	)		(590	)		212
Change in accrued taxes				52			48			(345	)
Other uses of cash:
	Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise			(1,022	)		(87	)		(1,442	)
Other changes in operating assets and liabilities				454			458			667

		Net cash provided by operating activities	$	1,971		$	1,970		$	1,134

			Payment due by period
			Total		Less than One year		1-3 years		3-5 years		More than 5 years
			(in millions)
Contractual Commitments: Utility
Purchase obligations:
	Power purchase agreements⁽¹⁾:
		Qualifying facilities	$	18,733	$	1,566	$	3,144	$	2,899	$	11,124
		Irrigation district and water agencies		573		77		113		114		269
		Other power purchase agreements		295		94		140		39		22
	Natural gas supply and transportation			960		829		131		—		—
	Nuclear fuel			290		46		109		82		53
	Preferred dividends and redemption requirements⁽²⁾			165		15		83		67		—
	Employee benefits:
		Pension⁽³⁾		40		20		20		—		—
		Postretirement benefits other than pension⁽³⁾		130		65		65		—		—
	Other commitments⁽⁴⁾			132		109		21		2		—
Operating leases				73		14		27		18		14

				21,391		2,835		3,853		3,221		11,482
Long-term debt⁽⁵⁾:
	Fixed rate obligations			11,831		295		929		1,155		9,452
	Variable rate obligations			2,257		805		1,452		—		—
Other long-term liabilities reflected on the Utility's balance sheet under GAAP:
	Rate reduction bonds			870		290		580		—		—
	Capital lease			10		2		4		4		—
PG&E Corporation
Purchase obligations:
	Purchase agreements—natural gas supply⁽⁶⁾			176		—		2		22		152
Long-term debt⁽⁵⁾:
	Convertible subordinated notes			426		27		53		53		293
	Other long-term debt			1		1		—		—		—
Operating leases				19		3		6		5		5

		Qualifying Facility				Irrigation District & Water Agency				Other
		Energy		Capacity		Operations & Maintenance		Debt Service		Energy		Capacity		Total
		(in millions)
2005		$	1,060	$	506	$	51	$	26	$	53	$	41	$	1,737
2006			1,082		506		31		26		39		36		1,720
2007			1,070		486		30		26		29		36		1,677
2008			1,040		476		33		26		15		9		1,599
2009			947		436		31		24		10		5		1,453
Thereafter			7,633		3,491		152		117		18		4		11,415

	Total	$	12,832	$	5,901	$	328	$	245	$	164	$	131	$	19,601

															Accumulated Other Comprehensive Income (Loss)			Total Common Share- holders' Equity
	Common Stock					Common Stock Held by Subsidiary						Reinvested Earnings (Accumulated Deficit)
	Common Stock								Unearned Compensation												Comprehensive income (Loss)
	Shares		Amount						Unearned Compensation												Comprehensive income (Loss)
Balance at December 31, 2001	387,898,848		$	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 (net of income tax benefit of $44 million)	—			—			—			—			—			(139	)		(139	)		(139	)
Net reclassification to earnings (net of income tax expense of $4 million)	—			—			—			—			—			13			13			13
Foreign currency translation adjustment (net of income tax expense of $1 million)	—			—			—			—			—			2			2			2
Other (net of zero income tax)	—			—			—			—			—			1			1			1

Comprehensive loss																					$	(997	)

Common stock issued	17,582,636			217			—			—			—			—			217
Common stock repurchased	(6,580	)		—			—			—			—			—			—
Warrants issued	—			71			—			—			—			—			71
Common stock warrants exercised	11,111			—			—			—			—			—			—

Balance at December 31, 2002	405,486,015			6,274			(690	)		—			(1,878	)		(93	)		3,613
Net income	—			—			—			—			420			—			420		$	420
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (net of income tax benefit of $10 million)	—			—			—			—			—			(8	)		(8	)		(8	)
Retirement plan remeasurement (net of income tax benefit of $3 million)	—			—			—			—			—			(4	)		(4	)		(4	)
Net reclassification to earnings (net of income tax expense of $27 million)	—			—			—			—			—			17			17			17
Foreign currency translation adjustment (net of income tax expense of $5 million)	—			—			—			—			—			3			3			3

Comprehensive income																					$	428

Common stock issued	8,796,632			166			—			—			—			—			166
Common stock warrants exercised	702,367			—			—			—			—			—			—
Common restricted stock issued	1,590,010			28			—			(28	)		—			—			—
Common restricted stock cancelled	(54,742	)		(1	)		—			1			—			—			—
Common restricted stock amortization	—			—			—			7			—			—			7
Other	—			1			—			—			—			—			1

Balance at December 31, 2003	416,520,282			6,468			(690	)		(20	)		(1,458	)		(85	)		4,215
Net income	—			—			—			—			4,504			—			4,504		$	4,504
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (net of income tax expense of $2 million)	—			—			—			—			—			3			3			3
NEGT losses reclassified to earnings upon elimination of equity interest by PG&E Corporation (net of income tax expense of $43 million)	—			—			—			—			—			77			77			77
Other	—			—			—			—			—			1			1			1

Comprehensive income																					$	4,585

Common stock issued	8,410,058			162			—			—			—			—			162
Common stock repurchased	(10,783,200	)		(167	)		—			—			(183	)		—			(350	)
Common stock held by subsidiary	—			—			(28	)		—			—			—			(28	)
Common stock warrants exercised	4,003,812			—			—			—			—			—			—
Common restricted stock issued	498,910			16			—			(16	)		—			—			—
Common restricted stock cancelled	(33,721	)		(1	)		—			1			—			—			—
Common restricted stock amortization	—			—			—			9			—			—			9
Tax benefit from employee stock plans	—			41			—			—			—			—			41
Other	—			(1	)		—			—			—			—			(1	)

Balance at December 31, 2004	418,616,141		$	6,518		$	(718	)	$	(26	)	$	2,863		$	(4	)	$	8,633

	Preferred Stock Without Mandatory Redemption Provisions		Common Stock		Additional Paid-in Capital		Common Stock Held by Subsidiary			Reinvested Earnings (Accumu- lated Deficit)			Accumu- lated Other Compre- hensive Income (Loss)			Total Share- holders' Equity			Comprehensive Income
Balance at December 31, 2001	$	294	$	1,606	$	1,964	$	(475	)	$	(989	)	$	(2	)	$	2,398
Net Income		—		—		—		—			1,819			—			1,819		$	1,819
Foreign currency translation adjustments (net of income tax expense of $1 million)		—		—		—		—			—			2			2			2

Comprehensive income																			$	1,821

Preferred stock dividend		—		—		—		—			(25	)		—			(25	)

Balance at December 31, 2002		294		1,606		1,964		(475	)		805			—			4,194
Net Income		—		—		—		—			923			—			923		$	923
Retirement plan remeasurement (net of income tax benefit of $2 million)		—		—		—		—			—			(3	)		(3	)		(3	)
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (net of income tax benefit of $2 million)		—		—		—		—			—			(3	)		(3	)		(3	)

Comprehensive income																			$	917

Preferred stock dividend		—		—		—		—			(22	)		—			(22	)

Balance at December 31, 2003		294		1,606		1,964		(475	)		1,706			(6	)		5,089
Net Income		—		—		—		—			3,982			—			3,982		$	3,982
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (net of income tax expense of $2 million)		—		—		—		—			—			3			3			3

Comprehensive income																			$	3,985

Equity contribution for settlement of POR payable (net of income taxes of $52 million)		—		—		77		—			—			—			77
Preferred stock dividend		—		—		—		—			(21	)		—			(21	)

Balance at December 31, 2004	$	294	$	1,606	$	2,041	$	(475	)	$	5,667		$	(3	)	$	9,130

			At December 31,
			2004		2003
			Carrying Amount	Fair Value	Carrying Amount	Fair Value
			(in millions)
Long-term debt (Note 3):
	PG&E Corporation
		Convertible subordinated notes⁽¹⁾	280	738	280	649
	Utility		5,632	5,813	4,839	4,905
Rate reduction bonds (Note 4)			870	911	1,160	1,252
Utility preferred stock with mandatory redemption provisions (Note 7)			122	127	137	167

		Hedging Transactions in Accordance with SFAS No. 133			Foreign Currency Translation Adjustment			Retirement Plan Remeasurement			Other			Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2001		$	36		$	(5	)	$	—		$	(1	)	$	30
Period change in:
	Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133		(139	)		—			—			—			(139	)
	Net reclassification to earnings		13			—			—			—			13
	Other		—			2			—			1			3

Balance at December 31, 2002			(90	)		(3	)		—			—			(93	)
Period change in:
	Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133		(8	)		—			—			—			(8	)
	Net reclassification to earnings		17			—			—			—			17
	Other		—			3			(4	)		—			(1	)

Balance at December 31, 2003			(81	)		—			(4	)		—			(85	)
Period change in:
	Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133		3			—			—			—			3
	NEGT losses reclassified to earnings upon elimination of equity interest by PG&E Corporation		77			—			—			—			77
	Other		—			—			—			1			1

Balance at December 31, 2004		$	(1	)	$	—		$	(4	)	$	1		$	(4	)

Sources			Uses
(in millions)
First Mortgage Bonds	$	6,700	Payments to Creditors	$	8,394
Term Loans		799	Disputed Claims Escrow		1,843
Accounts Receivable Financing Facility		350

Total Debt Financing		7,849
Cash Used to Pay Claims		2,388

Sources of Funds for Claims		10,237	Uses of Funds for Claims		10,237

Reinstated Pollution Control Bond-Related Obligations		814	Reinstated Pollution Control Bond-Related Obligations		814
Reinstated Preferred Stock		421	Reinstated Preferred Stock		421
Cash on Hand		225	Preferred Dividends		93
			Environmental Measures		10
			Transaction Costs		122

Total Sources of Funds	$	11,697	Total Uses of Funds	$	11,697

	Settlement Regulatory Asset			Utility Retained Generation Regulatory Assets			Total
	(in millions)
Authorized, pre-tax, January 1, 2004	$	3,730		$	1,249		$	4,979
Amortization from January 1 to March 31, 2004		(58	)		(21	)		(79	)

Recognition of regulatory assets, pre-tax, March 31, 2004		3,672			1,228			4,900
Deferred income taxes		(1,496	)		(500	)		(1,996	)

Recognition of regulatory assets, after tax, March 31, 2004	$	2,176		$	728		$	2,904

				December 31, 2004				December 31, 2003
				Revolving Credit Limit		Outstanding		Outstanding
				(in millions)
Short-Term Borrowings:
PG&E Corporation
		Senior credit facility		$	200	$	—	$	—

			Total credit facilities	$	200	$	—	$	—

Utility
		Accounts receivable financing		$	650	$	—	$	—
		Working capital facility		$	850	$	300	$	—

			Total credit facilities	$	1,500	$	300	$	—

	Credit facilities subject to compromise:
		5-year revolving credit facility				$	—	$	938

			Total credit facilities subject to compromise			$	—	$	938

	Short-term borrowings subject to compromise:
		Bank borrowings—drawn letters of credit for accelerated pollution control agreement				$	—	$	454
		Floating rate notes					—		1,240
		Commercial paper					—		873

			Total credit facilities and short-term borrowings subject to compromise			$	—	$	3,505

				December 31, 2004
Other Credit Facilities:
Utility
	Letters of credit⁽¹⁾:
		Pollution control bonds reimbursement agreements		$	620
		Working capital facility			285

			Total letters of credit	$	905

	First mortgage bonds issued to secure and support various debt and credit facilities⁽¹⁾:
		Pollution control loan agreements, variable rates, due 2007		$	620
		Pollution control loan agreements, 5.35%, due 2006			200
		Pollution control loan agreements, 3.50%, due 2007			345
		Pollution control bond bridge facilities, variable rates, due 2005			454
		Working capital facility			850

			Total first mortgage bonds issued to secure and support various debt and credit facilities	$	2,469

	188 Days ended July 7, 2003			Year ended December 31, 2002
	(in millions)
Operating revenues⁽¹⁾	$	786		$	1,766
Income (Loss) before income taxes⁽¹⁾		(595	)		(4,094	)

		One-Percentage Point Increase			One-Percentage Point Decrease
Effect on postretirement benefit obligation		$	30		$	(27	)
Effect on service and interest cost			9			(7	)

	2004				2003				2002
	Shares		Weighted Average Option Price		Shares		Weighted Average Option Price		Shares		Weighted Average Option Price
Outstanding at January 1	27,416,380		$	21.26	31,067,611		$	22.22	34,080,405		$	22.11
Granted	2,450,400			27.24	3,649,902			14.62	211,712			19.44
Exercised	(8,173,864	)		18.39	(3,818,837	)		19.15	(332,436	)		23.65
Cancelled	(814,358	)		21.37	(3,482,296	)		25.18	(2,892,070	)		20.56
Outstanding at December 31	20,878,558			22.76	27,416,380			21.26	31,067,611			22.22
Exercisable	13,981,720			24.67	16,072,654			25.34	15,487,462			27.05

		Quarter ended
		December 31		September 30		June 30		March 31
		(in millions, except per share amounts)
2004⁽¹⁾
PG&E CORPORATION
Operating revenues		$	2,986	$	2.623	$	2,749	$	2,722
Operating income⁽²⁾⁽³⁾			584		509		672		5,353
Income from continuing operations			187		228		372		3,033
Net income⁽⁴⁾			871		228		372		3,033
Earnings per common share from continuing operations, basic			0.45		0.55		0.89		7.36
Earnings per common share from continuing operations, diluted			0.44		0.53		0.88		7.15
Common stock price per share:
	High		34.46		30.40		30.32		29.35
	Low		30.32		27.50		25.90		26.47
UTILITY
Operating revenues		$	2,986	$	2,623	$	2,749	$	2,722
Operating income⁽²⁾⁽³⁾			584		516		682		5,362
Net income			248		248		412		3,074
Income available for common stock			243		244		408		3,066
2003⁽¹⁾
PG&E CORPORATION
Operating revenues⁽⁵⁾		$	2,538	$	3,103	$	2,729	$	2,065
Operating income			317		1,173		780		73
Income (loss) from continuing operations			37		508		328		(82	)
Net income (loss)⁽⁶⁾			37		510		227		(354	)
Earnings (loss) per common share from continuing operations, basic			0.09		1.25		0.81		(0.21	)
Earnings (loss) per common share from continuing operations, diluted			0.09		1.22		0.80		(0.21	)
Common stock price per share:
	High		27.98		24.00		22.01		15.35
	Low		23.43		20.63		13.41		11.69
UTILITY
Operating revenues⁽⁵⁾		$	2,538	$	3,103	$	2,730	$	2,067
Operating income			340		1,195		755		49
Net income (loss)			62		589		345		(73	)
Income (loss) available for common stock			58		583		339		(79	)