NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility ~~engages in~~generates revenues mainly through the ~~businesses~~sale and delivery of electricity and natural gas ~~distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage.~~to customers. The Utility is primarily regulated ~~primarily~~ by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). The Utility’s accounts for electric and gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.

This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. Therefore, the Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries, as well as, the accounts of variable interest entities (“VIEs”) for which the Utility ~~absorbs a majority of~~is the ~~risk of loss or gain.~~primary beneficiary. All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with U.S. generally accepted accounting principles ~~in the United States of America~~ (“GAAP”) for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X promulgated by the Securities and Exchange Commission (“SEC”) and therefore do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements. PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements reflect all adjustments that management believes are necessary for the fair presentation of their financial condition, ~~and~~ results of operations, and cash flows for the periods presented. The information at December 31, ~~2008~~2009 in both PG&E ~~Corporation’s~~Corp oration’s and the Utility’s Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets incorporated by reference into their combined 2009 Annual Report on Form 10-K ~~for the year ended December 31, 2008.~~filed on February 19, 2010. PG&E Corporation’s and the Utility’s combined 2009 Annual Report on Form 10-K, ~~for the year ended December 31, 2008,~~ together with the information incorporated by reference into such report, is referred to in this quarterly report ~~on Form 10-Q~~ as the ~~“2008~~“2009 Annual Report.”

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Notes 1 and 2 of the Notes to the Consolidated Financial Statements in the ~~2008~~2009 Annual Report. Any significant changes to those policies or new significant policies are described in Note 2 below.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions based on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict. Some of the more critical estimates and assumptions ~~discussed further below in these notes,~~ relate to the Utility’s regulatory assets and liabilities, environmental remediation liability, asset retirement obligations (“ARO”), income tax-related assets and liabilities, pension plan and other postretirement plan obligations, and accruals for legal matters. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment ~~that~~th at would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred.

This quarterly report should be read in conjunction with PG&E Corporation’s and the Utility’s audited Consolidated Financial Statements and ~~Notes to the Consolidated Financial Statements~~related notes included in the ~~2008~~2009 Annual Report.

NOTE 2: NEW AND SIGNIFICANT ACCOUNTING POLICIES

~~Significant Accounting Policies~~

~~Consolidation of Variable Interest Entities~~

PG&E Corporation and the Utility are required to consolidate any entity over which it has control. In most cases, control can be determined based on majority ownership. However, for certain entities, control is difficult to discern based on voting equity interests only. These entities are referred to as VIEs. Characteristics of a VIE include equity investment at risk that is not sufficient to permit the entity to finance its activities without additional subordinated financial support from other parties, or equity investors that lack any of the characteristics of a controlling financial interest. The primary beneficiary, defined as the entity that absorbs a majority of the expected losses of the VIE, receives a majority of the expected residual returns of the VIE, or both, is required to consolidate the VIE.

The Utility’s exposure to VIEs relates primarily to entities with which it has a power purchase agreement. For those entities, the Utility assesses operational risk, commodity price risk, credit risk, and tax benefit risk on a qualitative basis to determine whether the Utility is a primary beneficiary of the entity and is required to consolidate the entity. This qualitative assessment also typically involves comparing the contract life to the economic life of the plant to consider the significance of the commodity price risk that the Utility might absorb. As of September 30, 2009, the Utility is not the primary beneficiary of any entities with which it has power purchase agreements.

Although the Utility is not required to consolidate any of these VIEs as of September 30, 2009, it held a significant variable interest in three VIEs as a result of being a party to the following power purchase agreements:

·	A 25-year power purchase agreement approved by the CPUC in 2009 to purchase energy from a 250-megawatt (“MW”) solar photovoltaic energy facility beginning on the date of commercial operations (expected in 2012);

·	A 20-year power purchase agreement approved by the CPUC in 2009 to purchase energy from a 550-MW solar photovoltaic energy facility beginning on the date of commercial operations (expected in 2013); and

·	~~A 25-year power purchase agreement approved by the CPUC in 2008 to purchase energy from a 554-MW solar trough facility beginning on the date of commercial operations (expected in 2011).~~

Each of these VIEs is a subsidiary of another company whose activities are financed primarily through equity from investors and proceeds from non-recourse project-specific debt financing. Activities of the VIEs consist of renewable energy production from electric generating facilities for sale to the Utility. Under each of the power purchase agreements, the Utility is obligated to purchase as-delivered electric generation output from the VIEs. The Utility does not provide any other financial or other support to these VIEs. The Utility’s financial exposure is limited to the amounts paid for delivered electricity.

~~Asset Retirement Obligations~~

See Note 2 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report for a discussion of PG&E Corporation’s and the Utility’s accounting policy for ARO. A reconciliation of the changes in the ARO liability is as follows:

(in millions)
ARO liability at December 31, 2008 $ 1,684
Revision in estimated cash flows (172 )
Accretion 73
Liabilities settled (40 )
ARO liability at September 30, 2009 $ 1,545

Detailed studies of the cost to decommission the Utility’s nuclear power plants are conducted every three years in conjunction with the filing of the Nuclear Decommissioning Cost Triennial Proceedings. Estimated cash flows were revised as a result of the studies completed in the first quarter of 2009.

Pension and Other Postretirement Benefits

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for ~~certain~~eligible employees and retirees (referred to collectively as “pension benefits”), contributory postretirement medical plans for ~~certain~~eligible employees and retirees and their eligible dependents, and non-contributory postretirement life insurance plans for ~~certain~~eligible employees and retirees (referred to collectively as “other benefits”). PG&E Corporation and the Utility use a December 31 measurement date for all plans.

The net periodic benefit costs as reflected in PG&E Corporation’s Condensed Consolidated Statements of Income as a component of Operating and maintenance for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2010 and 2009 ~~and 2008~~ were as follows:

	Pension Benefits						Other Benefits							Pension Benefits						Other Benefits
	Three Months Ended September 30,						Three Months Ended September 30,							Three Months Ended March 31,						Three Months Ended March 31,
(in millions)	2009			2008			2009			2008				2010			2009			2010			2009
Service cost for benefits earned	$	62		$	59		$	7		$	7			$	69		$	66		$	10		$	8
Interest cost		158			148			23			21				161			155			23			21
Expected return on plan assets		(144	)		(173	)		(17	)		(22	)			(156	)		(145	)		(18	)		(17	)
Amortization of transition obligation		-			-			6			6				-			-			6			6
Amortization of prior service cost		16			12			4			4				13			11			6			4
Amortization of unrecognized (gain) loss		27			1			1			(3	)			11			25			1			1
Net periodic benefit cost		119			47			24			13				98			112			28			23
Less: transfer to regulatory account (1)		(78	)		(5	)		-			-				(58	)		(71	)		-			-
Total	$	41		$	42		$	24		$	13			$	40		$	41		$	28		$	23

(1) For the three months ended September 30, 2009 and 2008, the Utility recorded $78 million as an addition to the existing pension regulatory asset and $5 million as a reduction to the existing pension regulatory liability, respectively, to reflect the difference between pension expense or income for accounting purposes and pension expense or income for ratemaking purposes, which is based on a funding approach.
(1) The Utility recorded $58 million and $71 million for the three month periods ended March 31, 2010 and 2009, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.													(1) The Utility recorded $58 million and $71 million for the three month periods ended March 31, 2010 and 2009, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.

5752

~~Energy Efficiency Programs and Incentive Ratemaking~~

The CPUC previously established an incentive ratemaking mechanism applicable to the California investor-owned utilities’ implementation of their energy efficiency programs funded for the 2006-2008 and 2009-2011 program cycles. On December 18, 2008, based on their first interim claims, the CPUC awarded interim incentive earnings to the utilities for their 2006-2007 program performance. In the fourth quarter of 2008, the Utility recognized a CPUC award of $41.5 million for the Utility’s energy efficiency program performance in 2006-2007. Under the existing incentive ratemaking mechanism, the maximum amount of revenue that the Utility could earn and the maximum amount that the Utility could be required to reimburse customers over the 2006-2008 program cycle is $180 million.

On January 29, 2009, the CPUC established a new rulemaking proceeding to modify the existing incentive ratemaking mechanism for programs beginning in 2009 and future years, to adopt a new framework to review the utilities’ 2006-2008 program performance for the second interim claim, and to conduct a final review of the utilities’ performance over the 2006-2008 program period. On May 21, 2009, the Utility, San Diego Gas & Electric Company, Southern California Gas Company, and the Natural Resources Defense Council jointly requested that the CPUC approve a proposed settlement to resolve the utilities’ second interim claims and their final 2006-2008 true-up incentive claims. On July 10, 2009, the Utility submitted calculations, based on the methodology included in the proposed settlement, indicating that the Utility would be entitled to earn the remaining amount of the maximum incentives that could be earned for the 2006-2008 period. Based on the holdback amount proposed in the settlement, the Utility would be entitled to receive $76.6 million in incentive earnings and an additional $61.9 million would be held back and subject to verification in the final 2006-2008 true-up process to be completed in 2010. The assigned administrative law judge has ruled that there will be no hearings on the settlement proposal.

In accordance with the process established by the current incentive ratemaking mechanism, on October 15, 2009, the CPUC approved a second verification report issued by the CPUC's Energy Division relating to the second interim claims for the utilities’ 2006-2008 program performance. The report calculates potential incentive amounts for the Utility, based on different energy savings assumptions and measurement methods, that range up to $20.6 million with up to an additional $33.4 million to be held back pending completion of the 2006-2008 true-up process in 2010. In addition, on September 3 and October 1, 2009, the CPUC’s Energy Division released additional incentive award scenarios, including scenarios based on the proposed settlement, that result in a wide range of potential financial outcomes. It is uncertain what effect, if any, the issuance of the verification report or the scenarios will have on the likelihood of the proposed settlement becoming effective. Whether the proposed settlement will be approved and the amounts of any interim and final claims that may be awarded to the Utility are uncertain at this time.

On July 2, 2009, the utilities re-filed their applications containing their proposed 2009-2011 energy efficiency programs and budgets with the CPUC. On September 24, 2009, the CPUC modified the utilities’ 3-year cycles to cover 2010-2012 energy efficiency programs and authorized funding for these programs. The CPUC authorized the Utility to collect $1.3 billion to fund its programs, a 42% increase over 2006-2008 authorized funding levels. Consequently, the Utility will continue to collect bridge funding of approximately $435 million for the Utility’s 2009 energy efficiency programs, as previously authorized by the CPUC.

~~Spent Nuclear Fuel~~

As part of the Nuclear Waste Policy Act of 1982, Congress authorized the U.S. Department of Energy (“DOE”) and electric utilities with commercial nuclear power plants to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste no later than January 31, 1998, in exchange for fees paid by the utilities. In 1983, the DOE entered into a contract with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay. The DOE failed to develop a permanent storage site by January 31, 1998.

The Utility believes that the existing spent fuel pools at Diablo Canyon, which include newly constructed temporary storage racks, have sufficient capacity to enable the Utility to operate Diablo Canyon until approximately 2010 for Unit 1 and 2011 for Unit 2. Because the DOE failed to develop a permanent storage site, the Utility obtained a permit from the Nuclear Regulatory Commission (“NRC”) to build an on-site dry cask storage facility to store spent fuel through at least 2024. The construction of the dry cask storage facility is complete and the movement of spent nuclear fuel to dry cask storage began in June 2009.

After various parties appealed the NRC’s issuance of the permit, the U.S. Court of Appeals for the Ninth Circuit (“Ninth Circuit”) issued a decision in 2006 requiring the NRC to issue a supplemental environmental assessment report on the potential environmental consequences in the event of a terrorist attack at Diablo Canyon, as well as to review other contentions raised by the appealing parties related to potential terrorism threats. In August 2007, the NRC staff issued a final supplemental environmental assessment report concluding that there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage facility.

In October 2008, the NRC rejected the final contention that had been made during the appeal. The appellant has filed a petition for review of the NRC’s order in the Ninth Circuit. On December 31, 2008, the appellate court granted the Utility’s request to intervene in the proceeding. The Utility’s brief on appeal was filed on April 8, 2009. No date has been set for oral argument.

As a result of the DOE’s failure to build a national repository for nuclear waste, the Utility and other nuclear power plant owners sued the DOE to recover costs that they incurred to build on-site spent nuclear fuel storage facilities. The Utility seeks to recover $92 million of costs that it incurred through 2004. After several years of litigation, the DOE now concedes that the Utility is entitled to recover approximately $82 million of these costs, but the DOE continues to dispute the remaining amount. The trial to determine the appropriate method to calculate the amounts owed to the Utility began on October 15, 2009. The Utility also will seek to recover costs incurred after 2004 to build on-site storage facilities

PG&E Corporation and the Utility are unable to predict the amount and timing of any recoveries that the Utility will receive from the DOE. Amounts recovered from the DOE will be credited to customers through rates.

~~Application to Recover Hydroelectric Facility Divestiture Costs~~

On April 16, 2009, the CPUC approved a decision to authorize the Utility to recover $47 million of costs, including $12 million of interest, that the Utility incurred in connection with its efforts to determine the market value of its hydroelectric generation facilities in 2000 and 2001. These efforts were undertaken as required by the CPUC in connection with the proposed divestiture of the facilities to further the development of a competitive generation market in California. The CPUC subsequently withdrew this requirement. The Utility continues to own its hydroelectric generation assets. The Utility expects that the rate adjustments necessary to recover these authorized costs will be combined with other rate adjustments in the Utility’s annual electric rate true-up proceeding. These rate changes are expected to become effective in January 2010.

~~Retirement Plan Contribution Application~~

On September 10, 2009, the CPUC approved the all-party settlement among the Utility, the DRA, and the Coalition of California Utility Employees to resolve the Utility’s March 2, 2009 application to allow the Utility to recover amounts necessary for the Utility’s pension plan trust to attain fully funded status. Under the adopted settlement and based on projections to reach fully funded status by 2018, the Utility’s authorized pension-related revenue requirements would be $140.5 million, $177.2 million, and $215.7 million in 2011, 2012, and 2013, respectively. The Utility would request revenue requirements after 2013 in a separate proceeding. In addition, the settlement will allow the Utility to request an increase in revenue requirements if the ratio of trust assets to trust obligations falls below 85%.

The differences between pension benefit costs recognized in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and amounts recognized for ratemaking purposes are recorded as a regulatory asset or liability as amounts are probable of recovery from customers. (See Note 3 of the Notes to the Condensed Consolidated Financial Statements.) Therefore, the settlement is not expected to impact net income in future periods.

~~Cost of Capital Proceeding~~

On October 15, 2009, the CPUC approved a decision that maintains the Utility’s authorized cost of capital, including a ROE of 11.35%, through 2010. The decision approves a joint request made by the Utility and the DRA to avoid imposing a rate increase corresponding to an increase in the Utility’s ROE during a time of economic hardship. The Utility believes that this increase may otherwise have been triggered as of January 1, 2010 by the cost of capital adjustment mechanism previously adopted by the CPUC on May 29, 2008. The Utility’s capital structure, including a 52% equity component, will be maintained through 2012.

In addition, as requested by the Utility and the DRA, the CPUC extended the cost of capital adjustment mechanism through 2012. The cost of capital adjustment mechanism will be triggered if the 12-month October-through-September average yield for the applicable Moody’s Investors Services utility bond index increases or decreases by more than 1% as compared to the applicable benchmark. Finally, the CPUC agreed to defer the due date for the Utility’s next full cost of capital application from April 20, 2010 until April 20, 2012, so that any resulting changes would become effective on January 1, 2013.

2011 Gas Transmission and Storage Rate Case

~~On September 18,~~As discussed in the 2009 Annual Report the Utility filed an application with the CPUC to initiate the Utility’s 2011 Gas Transmission and Storage rate case so that the CPUC can determine the rates and terms and conditions of the Utility’s gas transmission and storage services beginning January 1, 2011. The rates, and terms and conditions of the Utility’s gas transmission and storage services for 2008 through 2010 were set by the terms of a CPUC-approved all-party settlement agreement known as the Gas Accord IV that was approved by the CPUC in September 2007. The Utility proposes to continue a majority of the Gas Accord IV’s terms and conditions of natural gas transportation and storage services.

The Utility has requested that the CPUC approve a 2011 natural gas transmission and storage revenue requirement of $529.1 million, an increase of $67.3 million over the 2010 adopted revenue requirement. The Utility also seeks attrition increases for 2012, 2013, and 2014 of $32.4 million, $30.7 million, and $22.6 million, respectively.

Under the Utility’s proposal, a substantial portion of the authorized revenue requirements, primarily those costs allocated to residential and small commercial customers (called “core” customers) would continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utility has proposed to simplify the current rate structure by, among other changes, setting rates for core and “non-core” customers based on forecast demand. The Utility’s ability to recover its remaining revenue requirements would continue to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. To reduce the Utility’s financial risk associated with these factors, the Utility has proposed to share equally with customers any under-collection or over-collection of natural gas transmission and storage revenue requirements. The Utility has proposed additional cost recovery mechanisms for costs that are difficult to forecast, such as the cost of electricity used to operate natural gas compressor stations and costs to comply with greenhouse gas regulations.

The Utility has requested that the CPUC issue a final decision by the end of ~~2010.~~2010 in order to put new rates into place by January 1, 2011. If the CPUC does not issue a final decision by the end of 2010, ~~to approve new rates effective January 1, 2011,~~ the September 2007 CPUC decision approving the 2008 Gas ~~Accord IV~~Transmission and Storage rate case provides that the rates and terms and conditions of service in effect as of December 31, 2010 will remain in effect, with an automatic 2% escalation in ~~the~~ rates, ~~as of~~for local transmission only, starting January 1, 2011.

Energy Efficiency Programs and Incentive Ratemaking

The CPUC has established a ratemaking mechanism to provide incentives to the California investor-owned utilities to meet the CPUC’s energy savings goals through implementation of the utilities’ 2006-2008 energy efficiency programs. In accordance with this mechanism, the CPUC has awarded the Utility interim incentive revenues totaling $75 million through December 31, 2009 based on the energy savings achieved through implementation of the Utility’s energy efficiency programs during the 2006 through 2008 program cycle. The amount of additional incentive revenues the Utility may earn, if any, is subject to verification of the final energy savings over the 2006-2008 program cycle and the completion of the true-up process.

On April 8, 2010, the assigned CPUC commissioner issued a ruling to provide guidance on the 2006-2008 true-up process, noting that the CPUC had directed the parties to convene a settlement conference to seek agreement on the 2010 final true-up amounts to avoid potential controversy and delay that could arise from basing the amounts solely upon the final verification report to be issued by the CPUC’s Energy Division. The ruling stated that the CPUC can consider alternative approaches in calculating the final true-up amounts in addition to the Energy Division’s report and directed the Energy Division to calculate various true-up amounts based on a range of possible scenarios that use different assumptions about energy savings, goals, and costs.

On May 4, 2010, the Energy Division released various scenarios of additional incentive amounts using data from the Energy Division’s draft verification report released on April 15, 2010. The calculation scenarios for the Utility range from a penalty of $75 million, based on a scenario using the Energy Division’s evaluated results, to a reward of $105 million. The CPUC has scheduled a settlement conference for May 28, 2010 for the parties to discuss the various scenarios. The CPUC's adopted schedule for the final true-up process calls for a final decision by the end of 2010. PG&E Corporation and the Utility are unable to predict the amount, if any, of additional incentive revenues or penalties the Utility may be assessed for the 2006-2008 program cycle.

It is expected that the CPUC will issue a decision by the end of 2010 to develop a more streamlined framework to determine incentive amounts for future energy efficiency program cycles.

Direct Access

As authorized by California Senate Bill 695, on March 11, 2010, the CPUC adopted a plan to re-open “direct access” on a limited and gradual basis to allow eligible customers of the three California investor-owned utilities to purchase electricity from independent electric service providers rather than from a utility. Effective April 11, 2010, all qualifying non-residential customers became eligible to take direct access service subject to annual and absolute caps. It is estimated that the total amount of direct access that will be allowed in the Utility’s service territory by the end of the four-year phase-in period will be equal to approximately 11% of the Utility’s total annual retail sales at the end of the period, roughly the highest level that was reached before the CPUC suspended direct access. Further legislative action is required to exceed these limits. The adopted phase-in schedule is designed to provide enough lead time for the utilities to account for small shifts in load and avoid unwarranted cost shifting and stranded costs.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. (See “Risk Factors” in the 2009 Annual Report.) These laws and requirements relate to a broad range of the Utility’s activities, including the discharge of pollutants into the air, water, and soil; the transportation, handling, storage, and disposal of spent nuclear fuel; remediation of hazardous wastes; and the reporting and reduction of carbon dioxide and other GHG emissions. Recent developments since the 2009 Annual Report was filed are discussed below.

Renewable Energy Resources

In an effort to reduce GHG emissions, California law requires California retail sellers of electricity, such as the Utility, to comply with a renewable portfolio standard (“RPS”) by increasing their deliveries of renewable energy (such as biomass, hydroelectric facilities with a capacity of 30 MW or less, wind, solar, and geothermal energy) each year, so that the amount of electricity delivered from these eligible renewable resources equals at least 20% of their total retail sales by the end of 2010. If a retail seller is unable to meet its target for a particular year, the current CPUC “flexible compliance” rules allow the retail seller to use future energy deliveries from already-executed contracts to satisfy any shortfalls, provided those deliveries occur within three years of the shortfall. 60;For the year ending December 31, 2009, the Utility’s RPS-eligible renewable resource deliveries equaled 14.4% of its total retail electricity sales. Most of the renewable energy that was delivered was purchased by the Utility from third parties, mainly under agreements with qualifying facility generators and other bilateral contracts. The Utility’s small hydroelectric and solar facilities also provided additional renewable energy. Some small hydroelectric energy is also provided under contracts with certain irrigation districts. As of March 31, 2010, the Utility believes it will meet the RPS mandate for 2010 through reliance on the CPUC’s flexible compliance rules.

In March 2010, the CPUC issued a decision authorizing the use of tradable renewable energy credits (“RECs”), the green attributes of renewable power, for RPS compliance. A tradable REC refers to a certificate of proof of the procurement of the green attributes separate from the associated energy, which certificate may be transferred to any third party and resold. Previously, investor-owned utilities were not allowed to use RECs purchased separately from the associated energy for purposes of RPS compliance. In its recent decision the CPUC authorized the limited use of REC-only transactions for RPS compliance. The CPUC defined a REC-only transaction broadly. Not only does it include a transaction for the procurement of stand–alone RECs, but it includes a transaction f or the procurement of both RECs and energy if the delivery of the energy to California customers must rely on intermediary energy transactions. As a result, most of the Utility’s existing contracts with out-of-state renewable generation facilities have been reclassified as REC-only contracts. The CPUC also imposed limits on both the quantity of REC-only transactions that the investor-owned utilities may use for RPS compliance and the price that the utilities may pay for REC-only transactions. The decision sets the maximum price per REC at $50 and limits the quantity of tradable RECs that the utilities can buy to 25% of their annual RPS compliance obligations, subject to certain grandfathering provisions that allow a utility to exceed these limits if the contracts have already been approved by the CPUC. If a utility has contracts pending before the CPUC that would cause them to exceed the quantity limit, the CPUC may still authorize the contract; however, if t he utility has already exceeded the REC-only quantity limitation, the utility may be limited in its ability to claim RPS compliance credit for deliveries under the contract. These limits expire on December 31, 2011, unless extended.

The Utility believes that the CPUC’s decision will significantly reduce out-of-state renewable energy procurement opportunities, at least in the near-term. In addition, the limitations on supplies of RPS-eligible procurement created by the CPUC’s decision may ultimately increase the cost of achieving the State’s renewable energy targets. Several parties, including the Utility, have requested modification and rehearing of numerous aspects of this decision. On May 6, 2010, the CPUC voted to stay its earlier decision authorizing the use of tradable RECs until the CPUC has issued a decision on the petitions for modification. The CPUC also imposed a temporary moratorium on CPUC approval of any contr acts for REC-only transactions that are signed after May 6, 2010 pending resolution of the petitions. The CPUC has indicated that it will consider the petitions for modification on June 24, 2010.

In addition, on March 12, 2010, the California Air Resources Board (“CARB”), the state agency charged with setting and monitoring emission limits, issued draft regulations that would require all load-serving entities, including the utilities, to meet gradually increasing annual renewable energy targets of 20% in 2012 through 2014, 24% in 2015 through 2017, 28% in 2018 through 2019, and 33% in 2020 and beyond. The draft regulations propose to adopt existing RPS definitions of eligible renewable resources, with some exceptions for publicly-owned utilities. However, the CARB is still considering whether it will allow the unlimited use of stand-alone RECs for compliance or if it will impose some limitation on their use. Under the draft regulations, any failure to meet one of the annual renewable e nergy targets would be a violation of an emission limitation and subject to penalties. The CARB has stated its intention to issue revised draft regulations by June 3, 2010. The CARB is scheduled to vote on the draft regulations on July 22-23, 2010.

The Utility’s ability to comply with the renewable energy requirements largely depends on the timely development of renewable generation facilities by third party developers. The development of renewable generation facilities by third parties or by the Utility is subject to many risks, including risks related to permitting, financing, technology, fuel supply, environmental matters, and the construction of sufficient transmission capacity.

Water Quality

There is continuing uncertainty about the status of state and federal regulations issued under Section 316(b) of the Clean Water Act, which require that cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, reflect the best technology available to minimize adverse environmental impacts. Although the EPA has not yet issued revised regulations, on May 4, 2010, the California Water Resources Control Board ("Water Board") adopted a policy on once-through cooling that generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the state's nuclear p ower generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are "wholly out of proportion" to the costs considered by the Water Board in developing its policy or if the installation of cooling towers would be "wholly unreasonable" after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts. The Utility believes that the costs to install cooling towers at Diablo Canyon, which could be as much as $4.5 billion, will meet the "wholly out of proportion" test. The Utility also believes that the installation of cooling towers at Diablo Canyon would be "wholly unreasonable." If the Water Board disagreed and if the installation of cooling towers at Diablo Canyon were not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. (See Note 16 of the Notes to the Consolidated Financia l Statements in the 2009 Annual Report for more information.) Assuming the Water Board does not require the installation of cooling towers at Diablo Canyon, the Utility could incur significant costs to comply with alternative compliance measures or to make payments to support various environmental mitigation projects. The Utility would seek to recover such costs in rates. The Utility’s Diablo Canyon operations must be in compliance with the Water Board’s policy by December 31, 2024.

Remediation

In February 2010, the Utility began contacting the owners of property located on eight former manufactured gas plant (“MGP”) sites in the Utility’s service territory to offer to test the soil for residues, and depending on the results of such tests, to take appropriate remedial action. Three of these sites are located in urban, residential areas of San Francisco. Until the Utility’s investigation of these MGP sites is complete, the extent of the Utility’s obligation to remediate is established, and any appropriate remedial actions are determined, the Utility is unable to determine the amounts it may spend in the future to remediate these sites and no amounts have been accrued for these sites (other than investigative costs for some of the sites). Although it is reasonably pos sible that the Utility will incur losses in the future related to these sites, the Utility is unable to reasonably estimate the amount of such loss. The Utility expects that it will recover 90% of the costs to remediate MGP sites under a ratemaking mechanism established by the CPUC. The Utility will seek to recover remaining costs through insurance. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements, for a discussion of estimated environmental remediation liabilities.)

OTHER MATTERS

The CPUC has authorized the Utility to recover $2.2 billion in estimated project costs, including $1.8 billion of capital expenditures to install approximately 10 million advanced electric and gas meters throughout the Utility’s service territory by the end of 2012. In addition, the Utility can recover in rates 90% of up to $100 million in costs that exceed the authorized $2.2 billion without a reasonableness review by the CPUC. The remaining 10% will not be recoverable in rates. If additional costs exceed the $100 million threshold, the Utility may request recovery of the additional costs, subject to a reasonableness review. As of March 31, 2010, the Utility has incurred $1.47 billion in connection with its SmartMeterTM program.

Advanced electric meters, which record energy usage in hourly or quarter-hourly increments, allow customers to track energy usage throughout the billing month and thus enable greater customer control over electricity costs. Usage data is collected through a wireless communication network and transmitted to the Utility’s information system where the data is stored and used for billing and other Utility business purposes. These meters will allow the implementation of “dynamic pricing” rates that the CPUC has ordered the Utility to implement. Dynamic pricing rates are designed to reflect the cost of electricity production during periods of high demand.

In late March 2010, the California State Senate established a committee to investigate and review the deployment of the “smart grid” throughout California, focusing on the Utility’s SmartMeterTM program. It is expected that the committee will investigate the integrity and reliability of new metering technologies and the consumer protections in place with respect to billing, disconnection, and real-time pricing. On April 26, 2010, a senior executive of the Utility testified before the committee stating that, of the approximately 5.5 million meters that have been installed, the Utility has determined that 8 meters failed to measure energy usage in line with accepted standards, and another approximately 0.7% of the meters experienced issues involving the meter’s wireless communications, the data stora ge on the device, or human error at installation. As the senior executive testified, these issues do not necessarily cause high or inaccurate bills. The committee is expected to submit its report to the California Senate, including recommendations for appropriate legislation, by November 30, 2010.

On March 30, 2010, the CPUC selected an independent consultant to assess the Utility’s SmartMeterTM program, including meter and billing accuracy, customer complaints, end-to-end operational processes, and overall program planning and performance. It is expected that the independent CPUC assessment will be completed by August 2010. A class action lawsuit filed in the Superior Court in Bakersfield, California, has been stayed pending the results of the CPUC’s investigation. The class action plaintiffs allege that the new meters, wireless network, and software and billing system, have led to electric bill overcharges.

Finally, on April 15, 2010, a private group filed an application asking the CPUC to impose a moratorium on installation and activation of the new meters pending an evidentiary hearing on the potential health, environmental, and safety impacts of the radio frequency ("RF") technology used in the Utility’s SmartMeterTM program.

The Utility is continuing to install the new meters. The outcome of these matters may have an effect on the Utility’s ability to recover costs to implement advanced metering if the CPUC finds that the costs are not reasonable or are otherwise disallowed. Further, if the Utility is prohibited from continuing to install the new meters, or if the Utility otherwise fails to recognize the expected benefits of its advanced metering infrastructure, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially adversely affected.

RISK MANAGEMENT ACTIVITIES

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; their financing arrangements; the marketplace for electricity, natural gas, electricity transmission, natural gas transportation, and storage; other goods and services; and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as ~~price risk~~“price risk” and ~~interest~~“interest rate risk.” The Utility is also exposed to ~~credit~~“credit risk, ~~which is~~” the risk that counterparties fail to perform their contractual obligations. ~~For a comprehensive discussion~~

The Utility actively manages market risks through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost 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 ~~PG&E Corporation’s market risk, see the section entitled “Risk Management Activities” in the 2008 Annual Report.~~energy and financial instruments such as 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.

Price Risk

~~Electricity Procurement~~The Utility is exposed to commodity price risk as a result of its electricity procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices will not affect earnings but may impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism.

~~On April 1, 2009, the CAISO’s Market Redesign~~The Utility’s natural gas transportation and ~~Technology Upgrade (“MRTU”) became operative. Among other features, the MRTU established new day-ahead, hour-ahead, and real-time wholesale electricity markets~~storage costs for non-core customers may not be fully recoverable. The Utility is subject to ~~bid caps~~price and volumetric risk for the portion of intrastate natural gas transportation and storage capacity that ~~increase over time.~~has not been sold under long-term contracts providing for the recovery of all fixed costs through the collection of fixed reservation charges. The Utility ~~expects to continue to rely~~sells most of its capacity based on ~~electricity from a diverse mix~~the volume of ~~resources, including third-party contracts, amounts allocated under DWR contracts, and its own electricity generation facilities to meet customer demand. A relatively small proportion of~~gas that the Utility’s ~~total customer demand must be met through purchases in~~customers actually ship, which exposes the ~~MRTU markets. As a result, exposure~~Utility to price volatility in the new MRTU markets is minimal. The CAISO must implement additional FERC-ordered changes over the next several years. Market risks, if any, associated with these changes will be assessed as the design and timelines are finalized during the 2009-2010 period.

~~Natural Gas Transportation and Storage~~volumetric risk.

The Utility uses value-at-risk to measure the shareholders’ exposure to price and volumetric risks resulting from variability in the price of, and demand for, natural gas transportation and storage ~~services.~~services that could impact revenues due to changes in market prices and customer demand. Value-at-risk measures this exposure over a rolling 12-month forward period and assumes that the contract positions are held through expiration. This calculation is based on a 95% confidence level, which means that there is a 5% probability that the impact to revenues on a pre-tax basis, over the rolling 12-month forward period, will be at least as large as the reported value-at-risk. Value-at-risk uses market data to quantify the Utility’s price exposure. When market data is not available, the ~~Utility~~Utilit y uses historical data or market proxies to extrapolate the required market data. Value-at-risk as a measure of portfolio risk has several limitations, including, but not limited to, inadequate indication of the exposure to extreme price movements and the use of historical data or market proxies that may not adequately capture portfolio risk.

The Utility’s value-at-risk calculated under the methodology described above was ~~$17~~$11 million at ~~September 30, 2009.~~March 31, 2010. The Utility’s high, low, and average values-at-risk at ~~September 30, 2009~~March 31, 2010 were ~~$34~~$17 million, $9$10 million, and ~~$17~~$14 million, respectively.

See Note 7 of the Notes to the Condensed Consolidated Financial Statements for further discussion of price risk management activities.

Interest Rate Risk

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 ~~September 30, 2009,~~March 31, 2010, if interest rates changed by 1% for all current PG&E Corporation and the Utility variable rate and short-term debt and investments, the change would ~~have an immaterial impact to~~affect net income ~~over~~for the ~~next~~ twelve ~~months.~~months ended March 31, 2010 by $10 million, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Credit Risk

The Utility conducts business with 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. If a counterparty failed to perform on its contractual obligation to deliver electricity or gas, then the Utility may find it necessary to procure electricity or gas at current market prices, which may be higher than the contract prices.

The Utility manages credit risk associated with its ~~wholesale customers and~~ counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored ~~periodically, and a detailed credit analysis is performed at least annually.~~periodically. The Utility ~~executes~~ties many energy contracts to master commodity enabling agreements that may require security (referred to as ~~“credit collateral”)~~“Credit Collateral” in the table below). Credit Collateral may be in the form of cash or letters of ~~credit,~~credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities if(as deemed appropriate by the Utility). Credit Collateral or performance assurance may be required from counterparti es when current net receivables and replacement cost exposure exceed contractually specified limits.

The following table summarizes the Utility’s net credit risk exposure to its ~~wholesale customers and~~ counterparties, as well as the Utility’s credit risk exposure to ~~its wholesale customers or~~ counterparties ~~with a~~accounting for greater than 10% net credit exposure, ~~at September 30, 2009~~as of March 31, 2010 and December 31, ~~2008:~~2009:

(in millions)
Gross Credit
Exposure Before Credit Collateral(1)
Credit Collateral
Net Credit Exposure(2)

Number of
Wholesale
Customers or Counterparties
>10%

Net Exposure to
Wholesale
Customers or Counterparties
>10%

September 30, 2009 $ 227 $ 45 $ 182 3 $ 148
December 31, 2008 $ 240 $ 84 $ 156 2 $ 107

(1) Gross credit exposure equals mark-to-market value on financially settled contracts, notes receivable, and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity.

(2) Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.

(in millions)	Gross Credit Exposure Before Credit Collateral (1)		Credit Collateral		Net Credit Exposure (2)		Number of Wholesale Customers or Counterparties >10%		Net Exposure to Wholesale Customers or Counterparties >10%
March 31, 2010	$	192	$	23	$	169		3	$	138
December 31, 2009	$	202	$	24	$	178		3	$	154

(1) Gross credit exposure equals mark-to-market value on physically and financially settled contracts, notes receivable, and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity.
(2) Net credit exposure is the Gross Credit Exposure Before Credit Collateral minus Credit Collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.

CRITICAL ACCOUNTING POLICIES

The preparation of Condensed Consolidated Financial Statements in accordance with ~~GAAP~~U.S. generally accepted accounting principals 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~~a re discussed in detail in the ~~2008~~2009 Annual Report. They include:

·	regulatory assets and liabilities;

·	environmental remediation liabilities;

·	asset retirement obligations;

·	accounting for income taxes; and

·	pension and other postretirement plans.

For the period ended ~~September 30, 2009,~~March 31, 2010, there were no changes in the methodology for computing critical accounting estimates, no additional accounting estimates met the standards for critical accounting policies, and no material changes to the important assumptions underlying the critical accounting estimates.

~~NEW ACCOUNTING POLICIES~~

~~Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133~~

On January 1, 2009, PG&E Corporation and the Utility adopted Statement of Financial Accounting Standards (“SFAS”) No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 requires an entity to provide qualitative disclosures about its objectives and strategies for using derivative instruments and quantitative disclosures that detail the fair value amounts of, and gains and losses on, derivative instruments. SFAS No. 161 also requires disclosures about credit risk-related contingent features of derivative instruments. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

~~Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51~~

On January 1, 2009, PG&E Corporation and the Utility adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 establishes accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 defines a “noncontrolling interest,” previously called a “minority interest,” as the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. Among other items, SFAS No. 160 requires that an entity (1) include a noncontrolling interest in its consolidated statement of financial position within equity separate from the parent’s equity, (2) report amounts inclusive of both the parent’s and noncontrolling interest’s shares in consolidated net income, and (3) separately report the amounts of consolidated net income attributable to the parent and noncontrolling interest on the consolidated statement of operations. If a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary must be measured at fair value, and a gain or loss must be recognized in net income based on such fair value.

PG&E Corporation has reclassified its noncontrolling interest in the Utility from Preferred Stock of Subsidiaries to equity in PG&E Corporation’s Condensed Consolidated Financial Statements in accordance with SFAS No. 160 for all periods presented. The Utility had no material noncontrolling interests in consolidated subsidiaries as of September 30, 2009 and December 31, 2008.

PG&E Corporation and the Utility applied the presentation and disclosure requirements of SFAS No. 160 retrospectively. Other than the change in presentation of noncontrolling interests, adoption of SFAS No. 160 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

~~Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement~~

On January 1, 2009, PG&E Corporation and the Utility adopted Emerging Issues Task Force (“EITF”) 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (“EITF 08-5”). EITF 08-5 clarifies the unit of account in determining the fair value of a liability. Specifically, it requires an entity to exclude any third-party credit enhancements that are issued with, and are inseparable from, a debt instrument from the fair value measurement of that debt instrument. Adoption of EITF 08-5 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

~~Equity Method Investment Accounting~~

On January 1, 2009, PG&E Corporation and the Utility adopted EITF 08-6, “Equity Method Investment Accounting Considerations” (“EITF 08-6”). EITF 08-6 applies to investments accounted for under the equity method and requires an entity to measure its equity investment initially at cost. Generally, contingent consideration associated with an equity method investment should only be included in the initial measurement of that investment if it is required to be recognized by specific authoritative guidance other than the Business Combinations Topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”). However, the investor in an equity method investment could be required to recognize a liability for the related contingent consideration features if the fair value of the investor’s share of the investee’s net assets exceeds the investor’s initial costs. An equity method investor is required to recognize other-than-temporary impairments of an equity method investment and shall account for a share issuance by an investee as if the investor had sold a proportionate share of its investment. Any gain or loss to the investor resulting from an investee’s share issuance shall be recognized in earnings. Adoption of EITF 08-6 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

~~Subsequent Events~~

On June 30, 2009, PG&E Corporation and the Utility adopted SFAS No. 165, “Subsequent Events” (“SFAS No. 165”). SFAS No. 165 does not significantly change the prior accounting practice for subsequent events, except for the requirement to disclose the date through which an entity has evaluated subsequent events and the basis for that date. PG&E Corporation and the Utility have evaluated material subsequent events through October 29, 2009, the issue date of PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. Other than this disclosure, adoption of SFAS No. 165 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

~~Interim Disclosures about Fair Value of Financial Instruments~~

On June 30, 2009, PG&E Corporation and the Utility adopted FASB Staff Position (“FSP”) SFAS 107-1 and Accounting Principles Board (“APB”) 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP requires disclosures about the fair value of financial instruments for interim reporting periods that were previously only required for annual reporting periods. In particular, an entity is required to disclose the fair value of financial assets and liabilities together with the related carrying amount and to disclose where the carrying amount is classified in the Condensed Consolidated Balance Sheets. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements.)

~~Recognition and Presentation of Other-Than-Temporary Impairments~~

On June 30, 2009, PG&E Corporation and the Utility adopted FSP SFAS 115-2 and SFAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments.” Under this FSP, to assess whether an other-than-temporary impairment exists for a debt security, an entity must (1) evaluate the likelihood of liquidating the debt security prior to recovering its cost basis and (2) determine if any impairment of the debt security is related to credit losses. In addition, this FSP requires enhanced disclosures of other-than-temporary impairments on debt and equity securities in the financial statements. However, this FSP does not amend recognition and measurement guidance for other-than-temporary impairments of equity securities. Adoption of this FSP did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

~~Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly~~

On June 30, 2009, PG&E Corporation and the Utility adopted FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.” This FSP provides guidance on estimating fair value when the volume or the level of activity for an asset or a liability has significantly decreased or when transactions are not orderly, when compared with normal market conditions. In particular, this FSP calls for adjustments to quoted prices or historical transaction data when estimating fair value in such circumstances. This FSP also provides guidance to identify such circumstances. Furthermore, this FSP requires fair value measurement disclosures made pursuant to the Fair Value Measurements and Disclosures Topic of the FASB ASC to be categorized by major security type (i.e., based on the nature and risks of the security). (See Note 8 of the Notes to the Condensed Consolidated Financial Statements.) Other than this change, adoption of this FSP did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

~~Topic 105 - Generally Accepted Accounting Principles - amendments based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards Codification~~TM ~~and the Hierarchy of Generally Accepted Accounting Principles~~

On July 1, 2009, PG&E Corporation and the Utility adopted Accounting Standards Update (“ASU”) No. 2009-01, “Topic 105 - Generally Accepted Accounting Principles - amendments based on Statement of Financial Accounting Standards No. 168 - The ~~FASB Accounting Standards Codification~~TM ~~and the Hierarchy of Generally Accepted Accounting Principles” (“ASU No. 2009-01”). ASU No. 2009-01 re-defines authoritative GAAP for nongovernmental entities to be only comprised of the~~ ~~FASB Accounting Standards Codification~~TM (“Codification”) and, for SEC registrants, guidance issued by the SEC. The Codification is a reorganization and compilation of all then-existing authoritative GAAP for nongovernmental entities, except for guidance issued by the SEC. The Codification is amended to effect non-SEC changes to authoritative GAAP. Adoption of ASU No. 2009-01 only changed the referencing convention of GAAP in PG&E Corporation’s and the Utility’s Notes to the Condensed Consolidated Financial Statements.

~~ACCOUNTING~~ ~~PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED~~

~~Employers’ Disclosures about Postretirement Benefit Plan Assets~~

In December 2008, the FASB issued FSP SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP amends and expands the disclosure requirements of the Compensation - Retirement Benefits Topic of the FASB ASC. In particular, this FSP requires an entity to provide qualitative disclosures about how investment allocation decisions are made, the inputs and valuation techniques used to measure the fair value of plan assets, and the concentration of risk within plan assets. In addition, this FSP requires quantitative disclosures showing the fair value of each major category of plan assets, the levels in which each asset is classified within the fair value hierarchy, and a reconciliation for the period of plan assets that are measured using significant unobservable inputs. This FSP is effective prospectively for PG&E Corporation and the Utility for the annual period ending December 31, 2009 and for subsequent annual periods. PG&E Corporation and the Utility will include the expanded disclosures described above in PG&E Corporation’s and the Utility’s Notes to the Consolidated Financial Statements for the annual period ending December 31, 2009.

~~Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140~~

In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140” (“SFAS No. 166”). SFAS No. 166 eliminates the concept of a qualifying special-purpose entity and clarifies the requirements for derecognizing a financial asset and for applying sale accounting to a transfer of a financial asset. In addition, SFAS No. 166 requires an entity to disclose more information about transfers of financial assets, the entity’s continuing involvement, if any, with transferred financial assets, and the entity’s continuing risks, if any, from transferred financial assets. SFAS No. 166 is effective prospectively for PG&E Corporation and the Utility beginning on January 1, 2010. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 166.

~~Amendments to FASB Interpretation No. 46(R)~~

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 amends the Consolidation Topic of the FASB ASC regarding when and how to determine, or re-determine, whether an entity is a variable interest entity (“VIE”). In addition, SFAS No. 167 replaces the Consolidation Topic of the FASB ASC’s quantitative approach for determining who has a controlling financial interest in a VIE with a qualitative approach. Furthermore, SFAS No. 167 requires ongoing assessments of whether an entity is the primary beneficiary of a VIE. SFAS No. 167 is effective prospectively for PG&E Corporation and the Utility beginning on January 1, 2010. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 167.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates (see “Risk Management Activities” above under Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations).

ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of ~~September 30, 2009,~~March 31, 2010, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934 (“1934 Act”) is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were ~~effective~~effec tive in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended ~~September 30, 2009~~March 31, 2010 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

6558

PART II. OTHER INFORMATION

~~ITEM 1. LEGAL PROCEEDINGS~~

~~Complaints Filed by the California Attorney General and the City and County of San Francisco~~

The complaint filed by the California Attorney General against PG&E Corporation and several of its present and former directors was dismissed on March 10, 2009 and the similar complaint filed by the City and County of San Francisco was dismissed on April 23, 2009. For more information regarding the resolution of these matters, see “Part I. Item 3. Legal Proceedings” in the 2008 Annual Report and “Part II, Item 1. Legal Proceedings” in PG&E Corporation’s and the Utility’s combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2009.

~~ITEM 1A. RISK FACTORS~~

A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility is set forth under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors” in the 2008 Annual Report.

The discussion of the potential impact of climate change appearing in the 2008 Annual Report under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors” under the following caption “~~The Utility’s future operations may be impacted by climate change that may have a material impact on the Utility’s financial condition and results of operations~~” ~~is updated as follows to reflect new scientific evidence regarding climate change:~~

A report issued on June 16, 2009 by the U.S. Global Change Research Program (an interagency effort led by the National Oceanic and Atmospheric Administration) states that climate changes caused by rising emissions of carbon dioxide and other heat-trapping gases have already been observed in the United States, including increased frequency and severity of hot weather, reduced runoff from snow pack, and increased sea levels. The impact of events or conditions caused by climate change could range widely, from highly localized to worldwide, and the extent to which the Utility’s operations may be affected is uncertain. For example, if reduced snowpack decreases the Utility’s hydroelectric generation capacity, there will be a need for additional generation capacity from other sources. Under certain conditions, the events or conditions caused by climate change could result in a full or partial disruption of the ability of the Utility, or one or more entities on which it relies, to generate, transmit, transport or distribute electricity or natural gas. The Utility has been studying the potential effects of climate change on the Utility’s operations and is developing contingency plans to adapt to those events and conditions that the Utility believes are most likely to occur. Events or conditions caused by climate change could have a greater impact on the Utility’s operations than has been forecast and could result in lower revenues or increased expenses, or both. If the CPUC were to fail to adjust the Utility’s rates to reflect the impact of events or conditions caused by climate change, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially adversely affected.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

~~On July~~During the quarter ended March 31, ~~2009,~~2010, PG&E Corporation ~~contributed~~made equity ~~of $35~~contributions totaling $20 million to the Utility in order to maintain the 52% common equity ~~target authorized by the CPUC~~component of its CPUC-authorized capital structure and to ensure that the Utility has adequate capital to fund its capital expenditures.

The Utility did not make any sales of unregistered equity securities during the quarter ended March 31, 2010.

Issuer Purchases of Equity Securities

PG&E Corporation common stock:

Period	Total Number of Shares Purchased			Average Price Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
January 1 through January 31, 2010		7,437	(1)	$	44.50		-	$	-
February 1 through February 28, 2010		-			-		-		-
March 1 through March 31, 2010		-			-		-		-
Total		7,437		$	44.50		-	$	-

(1) Shares tendered to satisfy tax withholding obligations arising upon the vesting of PG&E Corporation restricted stock.

During the quarter ended September 30, 2009, PG&E Corporation issued 331,404 shares of common stock at a conversion price of $15.09 per share in an unregistered offering upon conversion of $5 million principal amount of PG&E Corporation 9.50% Convertible Subordinated Notes originally issued in an unregistered offering in 2002.

~~During the quarter ended September 30, 2009, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the third quarter of 2009,~~March 31, 2010, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 5. OTHER INFORMATION

Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends

The Utility’s earnings to fixed charges ratio for the ~~nine~~three months ended ~~September 30, 2009~~March 31, 2010 was ~~3.19.~~$3.40. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the ~~nine~~three months ended ~~September 30, 2009~~March 31, 2010 was ~~3.13.~~$3.33. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utility’s Registration Statement Nos. 33-62488 and 333-149361 relating to various series of the Utility’s first preferred stock and its senior notes, respectively.

PG&E Corporation’s earnings to fixed charges ratio for the ~~nine~~three months ended ~~September 30, 2009~~March 31, 2010 was ~~2.99.~~$3.14. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. 333-149360 relating to its senior notes.

6759

ITEM 6. EXHIBITS


~~3.1~~	~~Bylaws of PG&E Corporation amended as of September 16, 2009~~

~~3.2~~3	Bylaws of Pacific Gas and Electric Company amended as of ~~September 16,~~February 17, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 1-2348), Exhibit 3.5)

4	Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Current Report on Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)

*10.1	Separation Agreement between Pacific Gas and Electric Company and Barbara Barcon effective March 4, 2010

*10.2	Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

*10.3	Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

32.1***32.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

32.2***32.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

*~~Pursuant to Item 601(b) (32) of SEC Regulation S-K, these Exhibits are furnished rather than filed with this report.~~101.INS	XBRL Instance Document

***101.SCH	XBRL Taxonomy Extension Schema Document

***101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

***101.LAB	XBRL Taxonomy Extension Labels Linkbase Document

***101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

* Management contract or compensatory agreement.

** Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

***

Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these sections. These files are being submitted only by PG&E Corporation and not by its subsidiary, Pacific Gas and Electric Company.

6860

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.

PG&E CORPORATION

KENT M. HARVEY

Kent M. Harvey

Senior Vice President and Chief Financial Officer

(duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY

~~BARBARA L. BARCON~~SARA A. CHERRY

~~Barbara L. Barcon~~Sara A. Cherry

Vice President, Finance and Chief Financial Officer

(duly authorized officer and principal financial officer)

Dated: ~~October 29, 2009~~

May 7, 2010

6961

EXHIBIT INDEX


~~3.1~~	~~Bylaws of PG&E Corporation amended as of September 16, 2009~~

~~3.2~~3	Bylaws of Pacific Gas and Electric Company amended as of ~~September 16,~~February 17, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 1-2348), Exhibit 3.5)

4	Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Current Report on Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)

10.1 10.2 *10.3	Separation Agreement between Pacific Gas and Electric Company and Barbara Barcon effective March 4, 2010 Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

32.1***32.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

32.2***32.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002


*~~Pursuant to Item 601(b) (32) of SEC Regulation S-K, these Exhibits are furnished rather than filed with this report.~~101.INS	XBRL Instance Document

***101.SCH	XBRL Taxonomy Extension Schema Document

***101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

***101.LAB	XBRL Taxonomy Extension Labels Linkbase Document

***101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

* Management contract or compensatory agreement.

** Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

***

7062


UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549 FORM 10-Q
(Mark One)

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September 30, 2009~~March 31, 2010 OR

[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to __________

Commission File Number _______________		Exact Name of Registrant as specified in its charter _______________				State or other Jurisdiction of Incorporation ______________			IRS Employer Identification Number ___________

1-12609		PG&E Corporation				California			94-3234914
1-2348		Pacific Gas and Electric Company				California			94-0742640

Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177						PG&E Corporation One Market, Spear Tower Suite 2400 San Francisco, California 94105
Address of principal executive offices, including zip code

Pacific Gas and Electric Company (415) 973-7000						PG&E Corporation (415) 267-7000
Registrant's telephone number, including area code

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. [X] Yes [ ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive ~~Date~~Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ~~[X]~~
PG&E Corporation				[X] Yes [ ] No

Pacific Gas and Electric Company:				[ ] Yes [ ] No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

PG&E Corporation:			[X] Large accelerated filer					[ ] Accelerated Filer
			[ ] Non-accelerated filer				[ ] Smaller reporting company
Pacific Gas and Electric Company:			[ ] Large accelerated filer					[ ] Accelerated Filer
			[X] Non-accelerated filer				[ ] Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:					[ ] Yes [X] No

Pacific Gas and Electric Company:					[ ] Yes [X] No

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Common Stock Outstanding as of ~~October 27, 2009:~~April 30, 2010:

PG&E Corporation						~~370,960,212~~372,345,954
Pacific Gas and Electric Company						264,374,809

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of Income		3
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company
		Condensed Consolidated Statements of Income		8
		Condensed Consolidated Balance Sheets		9
		Condensed Consolidated Statements of Cash Flows		11
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		Organization and Basis of Presentation	13
	NOTE 2:		New and Significant Accounting Policies	13
	NOTE 3:		Regulatory Assets, Liabilities, and Balancing Accounts	15
	NOTE 4:		Debt	18
	NOTE 4:5:		Equity	19
	~~Debt~~NOTE 6:		Earnings Per Share	20
	NOTE 7:		Derivatives and Hedging Activities	22
	NOTE 5:		~~Equity~~8:	23Fair Value Measurements	26
	NOTE 6:		~~Earnings Per Share~~9:	23
	~~NOTE 7:~~		~~Derivatives and Hedging Activities~~	25
	~~NOTE 8:~~		~~Fair Value Measurements~~	29
	~~NOTE 9:~~		Related Party Agreements and Transactions	3332
	NOTE 10:		Resolution of Remaining Chapter 11 Disputed Claims	32
	NOTE 11:		Commitments and Contingencies	33
					~~NOTE 11:~~
~~Commitments and Contingencies~~	34

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			4139
	Cautionary Language Regarding Forward-Looking Statements			4341
	Results of Operations			4442
	Liquidity and Financial Resources			5147
	Contractual Commitments			5551
	Capital Expenditures			5551
	Off-Balance Sheet Arrangements			5652
	Contingencies			5652
	Regulatory Matters			5652
	Environmental Matters			53
	Other Matters			55
	Risk Management Activities			6056
	Critical Accounting Policies			61
	~~New Accounting Policies~~			61
	~~Accounting Pronouncements Issued But Not Yet Adopted~~			6358

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			58
ITEM 4.	65
~~ITEM 4.~~	CONTROLS AND PROCEDURES			6558

PART II.	OTHER INFORMATION

ITEM 1.	~~LEGAL PROCEEDINGS~~2.			66
~~ITEM 1A.~~	~~RISK FACTORS~~			66
~~ITEM 2.~~	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			59
ITEM 5.	66OTHER INFORMATION			59
ITEM 5.	~~OTHER INFORMATION~~6.			67
~~ITEM 6.~~EXHIBITS	~~EXHIBITS~~	6860

PG&E CORPORATION	PG&E CORPORATION													PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME	CONDENSED CONSOLIDATED STATEMENTS OF INCOME													CONDENSED CONSOLIDATED STATEMENTS OF INCOME
		(Unaudited)													(Unaudited)
		Three Months Ended						Nine Months Ended							Three Months Ended
		September 30,						September 30,							March 31,
(in millions, except per share amounts)		2009			2008			2009			2008				2010			2009
Operating Revenues
Electric		$	2,630		$	2,880		$	7,610		$	8,039			$	2,510		$	2,426
Natural gas			605			794			2,250			2,946				965			1,005
Total operating revenues			3,235			3,674			9,860			10,985				3,475			3,431
Operating Expenses
Cost of electricity			997			1,282			2,763			3,406				920			883
Cost of natural gas			134			351			879			1,613				495			557
Operating and maintenance			1,047			983			3,144			3,010				991			1,059
Depreciation, amortization, and decommissioning			450			419			1,298			1,240				451			419
Total operating expenses			2,628			3,035			8,084			9,269				2,857			2,918
Operating Income			607			639			1,776			1,716				618			513
Interest income			1			23			27			82				2			9
Interest expense			(174	)		(178	)		(533	)		(550	)			(168	)		(181	)
Other income (expense), net			23			(14	)		63			(4	)
Other (expense) income, net																(6	)		18
Income Before Income Taxes			457			470			1,333			1,244				446			359
Income tax provision			136			163			376			413				185			115
Net Income			321			307			957			831				261			244
Preferred stock dividend requirement of subsidiary			3			3			10			10
Preferred dividend requirement of subsidiary																3			3
Income Available for Common Shareholders		$	318		$	304		$	947		$	821			$	258		$	241
Weighted Average Common Shares Outstanding, Basic			370			357			367			356				371			364
Weighted Average Common Shares Outstanding, Diluted			388			358			386			357				389			366
Net Earnings Per Common Share, Basic		$	0.84		$	0.83		$	2.53		$	2.25			$	0.69		$	0.65
Net Earnings Per Common Share, Diluted		$	0.83		$	0.83		$	2.49		$	2.24			$	0.67		$	0.65
Dividends Declared Per Common Share		$	0.42		$	0.39		$	1.26		$	1.17			$	0.46		$	0.42

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.													See accompanying Notes to the Condensed Consolidated Financial Statements.

							(Unaudited)
	(Unaudited)						Balance At
	Balance At						March 31,			December 31,
(in millions)	September 30, 2009			December 31, 2008			2010			2009
ASSETS
Current Assets
Cash and cash equivalents	$	700		$	219		$	258		$	527
Restricted cash		569			1,290			629			633
Accounts receivable:
Customers (net of allowance for doubtful accounts of $68 million in 2009 and $76 million in 2008)		1,609			1,751
Customers (net of allowance for doubtful accounts of $69 million in 2010 and $68 million in 2009)								1,528			1,609
Accrued unbilled revenue		807			685			638			671
Regulatory balancing accounts		882			1,197			1,468			1,109
Inventories:
Gas stored underground and fuel oil		141			232			59			114
Materials and supplies		204			191			196			200
Income taxes receivable		58			120			112			127
Prepaid expenses and other		640			718			733			667
Total current assets		5,610			6,403			5,621			5,657
Property, Plant, and Equipment
Electric		29,875			27,638			30,918			30,481
Gas		10,524			10,155			10,823			10,697
Construction work in progress		1,767			2,023			1,993			1,888
Other		15			17			14			14
Total property, plant, and equipment		42,181			39,833			43,748			43,080
Accumulated depreciation		(13,997	)		(13,572	)		(14,371	)		(14,188	)
Net property, plant, and equipment		28,184			26,261			29,377			28,892
Other Noncurrent Assets
Regulatory assets		5,931			5,996			5,602			5,522
Nuclear decommissioning funds		1,870			1,718			1,929			1,899
Income taxes receivable		506			-			596			596
Other		450			482			415			379
Total other noncurrent assets		8,757			8,196			8,542			8,396
TOTAL ASSETS	$	42,551		$	40,860		$	43,540		$	42,945

								(Unaudited)
	(Unaudited)							Balance At
	Balance At							March 31,			December 31,
(in millions, except share amounts)	September 30, 2009			December 31, 2008				2010			2009
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	500		$	287			$	1,251		$	833
Long-term debt, classified as current		342			600				842			342
Energy recovery bonds, classified as current		382			370				390			386
Accounts payable:
Trade creditors		864			1,096				882			984
Disputed claims and customer refunds		816			1,580				772			773
Regulatory balancing accounts		629			730				312			281
Other		370			343				481			349
Interest payable		794			802				795			818
Income taxes payable		589			-				268			214
Deferred income taxes		172			251				506			332
Other		1,491			1,567				1,281			1,501
Total current liabilities		6,949			7,626				7,780			6,813
Noncurrent Liabilities
Long-term debt		9,839			9,321				9,882			10,381
Energy recovery bonds		928			1,213				730			827
Regulatory liabilities		4,152			3,657				4,190			4,125
Pension and other postretirement benefits		2,221			2,088				1,968			1,773
Asset retirement obligations		1,545			1,684				1,603			1,593
Income taxes payable		-			35
Deferred income taxes		4,321			3,397				4,656			4,732
Deferred tax credits		90			94
Other		2,092			2,116				2,110			2,116
Total noncurrent liabilities		25,188			23,605				25,139			25,547
Commitments and Contingencies
Equity
Shareholders’ Equity
Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued		-			-				-			-
Common stock, no par value, authorized 800,000,000 shares, issued 370,877,751 common and 670,552 restricted shares in 2009 and issued 361,059,116 common and 1,287,569 restricted shares in 2008		6,265			5,984
Common stock, no par value, authorized 800,000,000 shares, issued 371,222,918 common and 480,848 restricted shares in 2010 and issued 370,601,905 common and 670,552 restricted shares in 2009									6,307			6,280
Reinvested earnings		4,097			3,614				4,302			4,213
Accumulated other comprehensive loss		(200	)		(221	)			(240	)		(160	)
Total shareholders’ equity		10,162			9,377				10,369			10,333
Noncontrolling Interest – Preferred Stock of Subsidiary		252			252				252			252
Total equity		10,414			9,629				10,621			10,585
TOTAL LIABILITIES AND EQUITY	$	42,551		$	40,860			$	43,540		$	42,945

See accompanying Notes to the Condensed Consolidated Financial Statements.							See accompanying Notes to the Condensed Consolidated Financial Statements.

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(193	)	$	(190	)
Income taxes, net		-			294
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	169		$	154
Capital expenditures financed through accounts payable		215			235
Noncash common stock issuances		-			33

See accompanying Notes to the Condensed Consolidated Financial Statements.

(in millions)
ARO liability at December 31, 2008	$	1,684
Revision in estimated cash flows		(172	)
Accretion		73
Liabilities settled		(40	)
ARO liability at September 30, 2009	$	1,545

	Pension Benefits						Other Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2009			2008			2009			2008
Service cost for benefits earned	$	194		$	177		$	22		$	22
Interest cost		468			436			66			61
Expected return on plan assets		(434	)		(522	)		(51	)		(70	)
Amortization of transition obligation		-			-			19			19
Amortization of prior service cost		39			35			12			12
Amortization of unrecognized (gain) loss		76			1			2			(11	)
Net periodic benefit cost		343			127			70			33
Less: transfer to regulatory account (1)		(221	)		(3	)		-			-
Total	$	122		$	124		$	70		$	33

(1) For the nine months ended September 30, 2009 and 2008, the Utility recorded $221 million as an addition to the existing pension regulatory asset and $3 million as a reduction to the existing pension regulatory liability, respectively, to reflect the difference between pension expense or income for accounting purposes and pension expense or income for ratemaking purposes, which is based on a funding approach.

	Receivable (Payable)						Receivable (Payable)
	Balance At						Balance at
(in millions)	September 30, 2009			December 31, 2008			March 31, 2010			December 31, 2009
Utility generation	$	199		$	164		$	572		$	355
Gas fixed cost		167			60
Transmission revenue		147			173
Distribution revenue adjustment mechanism								287			152
Public purpose programs		(70	)		(263	)		128			83
Energy procurement costs		(117	)		598			115			128
Gas fixed cost								(15	)		93
Energy recovery bonds		(167	)		(231	)		(163	)		(185	)
Other		94			(34	)		232			202
Total regulatory balancing accounts, net	$	253		$	467		$	1,156		$	828

	PG&E Corporation			Utility			PG&E Corporation			Utility
(in millions)	Total Equity			Total Shareholders’ Equity			Total Equity			Total Shareholders’ Equity
Balance at December 31, 2008	$	9,629		$	9,787
Balance at December 31, 2009							$	10,585		$	11,185
Net income		957			983			261			264
Common stock issued		261			-			10			-
Share-based compensation amortization		17			-			15			-
Common stock dividends declared and paid		(309	)		(468	)		-			(179	)
Common stock dividends declared but not yet paid		(156	)		-			(169	)		-
Preferred stock dividend requirement		-			(10	)		-			(3	)
Preferred stock dividend requirement of subsidiary		(10	)		-			(3	)		-
Tax benefit from employee stock plans		4			3			2			1
Other comprehensive income		21			21			(80	)		(80	)
Equity contribution		-			688			-			20
Balance at September 30, 2009	$	10,414		$	11,004
Balance at March 31, 2010							$	10,621		$	11,208


(1) Distributed earnings, basic may differ from actual per share amounts paid as dividends, as the EPS computation under GAAP requires the use of the weighted average, rather than the actual, number of shares outstanding.

	September 30, 2008
(in millions, except per share amounts)	Three Months Ended		Nine Months Ended
Diluted
Income Available for Common Shareholders	$	304	$	821
Less: distributed earnings to common shareholders		140		419
Undistributed earnings	$	164	$	402

Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders	$	140	$	419
Undistributed earnings allocated to common shareholders		156		382
Total common shareholders earnings	$	296	$	801

Weighted average common shares outstanding, basic		357		356
Convertible Subordinated Notes		19		19
Weighted average common shares outstanding and participating securities, basic		376		375
Weighted average common shares outstanding, basic		357		356
Employee share-based compensation		1		1
Weighted average common shares outstanding, diluted		358		357
Convertible Subordinated Notes		19		19
Weighted average common shares outstanding and participating securities, diluted		377		376
Net earnings per common share, diluted
Distributed earnings, diluted	$	0.39	$	1.17
Undistributed earnings, diluted		0.44		1.07
Total earnings per common share, diluted	$	0.83	$	2.24

	Three Months Ended
(in millions, except per share amounts)	March 31, 2009
Diluted
Income Available for Common Shareholders	$	241
Less: distributed earnings to common shareholders		154
Undistributed earnings	$	87

Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders	$	154
Undistributed earnings allocated to common shareholders		83
Total common shareholders earnings	$	237

Weighted average common shares outstanding, basic		364
Convertible subordinated notes		17
Weighted average common shares outstanding and participating securities, basic		381
Weighted average common shares outstanding, basic		364
Employee share-based compensation		2
Weighted average common shares outstanding, diluted		366
Convertible subordinated notes		17
Weighted average common shares outstanding and participating securities, diluted		383
Net earnings per common share, diluted
Distributed earnings, diluted	$	0.42
Undistributed earnings, diluted		0.23
Total earnings per common share, diluted	$	0.65

·	periodic expirations or terminations of existing electricity purchase contracts, including the DWR’s contracts;

·	the execution of new electricity purchase contracts;

·	fluctuation in the output of hydroelectric and other renewable power facilities owned or under contract;


·	changes in the Utility’s customers’ electricity demands due to customer and economic growth or decline, weather, implementation of new energy efficiency and demand response programs, direct access, and community choice aggregation;

·	the acquisition, retirement, or closure of generation facilities; and

·	changes in market prices that make it more economical to purchase power in the market rather than use the Utility’s existing resources.

		Contract Volumes (1)									Contract Volume (1)
Underlying Product	Instruments	Less Than 1 Year		Greater Than 1 Year But Less Than 3 Years		Greater Than 3 Years But Less Than 5 Years		Greater Than 5 Years (2)		Instruments	Less Than 1 Year		Greater Than 1 Year But Less Than 3 Years		Greater Than 3 Years But Less Than 5 Years		Greater Than 5 Years (2)
Natural Gas (3) (MMBtus (4))	Forwards, Futures, and Swaps		331,103,829		192,707,140		21,277,500		-	Forwards, Futures, and Swaps		354,147,125		211,026,845		17,875,000		-
	Options		136,232,644		86,837,080		-		-	Options		198,987,080		104,650,000		11,100,000		-

Electricity (Megawatt-hours)	Forwards, Futures, and Swaps		3,508,656		7,644,024		5,093,912		4,768,447	Forwards, Futures, and Swaps		4,050,541		8,296,859		4,274,287		4,082,736
	Options		9,400		11,450		110,980		557,512	Options		389,000		7,450		156,588		503,904
	Congestion Revenue Rights		55,374,468		64,267,318		59,648,715		107,581,890	Congestion Revenue Rights		75,220,639		66,937,314		66,870,770		111,554,263

PG&E Corporation Equity (Shares)	Dividend Participation Rights		16,370,789		-		-		-	Dividend Participation Rights		16,370,789		-		-		-

(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each time period.	(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each time period.									(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each time period.
(2) Derivatives in this category expire between 2014 and 2022.
(2) Derivatives in this category expire between 2015 and 2022.										(2) Derivatives in this category expire between 2015 and 2022.
(3) Amounts shown are for the combined positions of the electric and core gas portfolios.	(3) Amounts shown are for the combined positions of the electric and core gas portfolios.									(3) Amounts shown are for the combined positions of the electric and core gas portfolios.
(4) Million British Thermal Units.	(4) Million British Thermal Units.									(4) Million British Thermal Units.

(in millions)	Gross Derivative Balance (1)			Netting (2)			Cash Collateral (2)		Total Derivative Balances
Commodity Risk (PG&E Corporation and Utility)
Current Assets – Prepaid expenses and other	$	27		$	(10	)	$	46	$	63
Other Noncurrent Assets – Other		53			(34	)		55		74
Current Liabilities – Other		(332	)		10			168		(154	)
Noncurrent Liabilities – Other		(518	)		34			161		(323	)
Total commodity risk	$	(770	)	$	-		$	430	$	(340	)

Other Risk Instruments (3) (PG&E Corporation Only)
Current Liabilities – Other	$	(7	)	$	-		$	-	$	(7	)
Total derivatives	$	(777	)	$	-		$	430	$	(347	)

(1) See Note 8 below for a discussion of the valuation techniques used to calculate the fair value of these instruments.
(2) Positions, by counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.
(3) This category relates to the dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.

(in millions)
Commodity Risk (PG&E Corporation and Utility)
Unrealized gain/(loss) - Regulatory assets andliabilities (1)	$	32
Realized gain/(loss) - Cost of electricity(2)		(558	)
Realized gain/(loss)- Cost of natural gas (2)		(30	)
Total commodity risk instruments	$	(556	)
Other Risk Instruments(3) (PG&E Corporation Only)
Other income, net	$	1
Total other risk instruments	$	1

(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.
(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.
(3) This category relates to dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.

	Commodity Risk (PG&E Corporation and Utility)
	Three months ended March 31,
(in millions)	2010			2009
Unrealized gain/(loss) - Regulatory assets and liabilities (1)	$	(289	)	$	(307	)
Realized gain/(loss) - Cost of electricity (2)		(106	)		(202	)
Realized gain/(loss) - Cost of natural gas (2)		(39	)		(23	)
Total commodity risk instruments	$	(434	)	$	(532	)
	Other Risk Instruments (3) (PG&E Corporation Only)
Other expense (income), net	$	1		$	(2	)
Total other risk instruments	$	1		$	(2	)

(in millions)
Derivatives in a liability position with credit-risk-relatedcontingencies that are not fully collateralized		$	(541	)
Derivatives in a liability position with credit-risk-related contingencies that are not fully collateralized						$	(551	)
Related derivatives in an asset position			57				-
Collateral posting in the normal course of business relatedto these derivatives			70
Collateral posting in the normal course of business related to these derivatives							81
Net position of derivative contracts/additional collateral posting requirements (1)		$	(414	)		$	(470	)

(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit-risk-related contingencies.	(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit-risk-related contingencies.				(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit-risk-related contingencies.

Fair Value Measurements at March 31, 2010
(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Money market investments	$	195	$	-	$	-	$	195
Nuclear decommissioning trusts
U.S. equity securities (1)		813		30		-		843
Non-U.S. equity securities		328		-		-		328
U.S. government and agency securities		664		73		-		737
Municipal securities		4		86		-		90
Other fixed income securities		-		76		-		76
Total nuclear decommissioning trusts (2)		1,809		265		-		2,074
Price risk management instruments
Electric (3)		47		-		-		47
Total price risk management instruments		47		-		-		47
Rabbi trusts
Equity securities		22		-		-		22
Life insurance contracts		-		62		-		62
Total rabbi trusts		22		62		-		84
Long-term disability trust
U.S. equity securities (1)		3		28		-		31
Corporate debt securities (1)		-		148		-		148
Total long-term disability trust		3		176		-		179
Total assets	$	2,076	$	503	$	-	$	2,579
Liabilities:
Dividend participation rights	$	-	$	-	$	7	$	7
Price risk management instruments
Electric (4)		-		50		295		345
Gas (5)		-		1		41		42
Total price risk management instruments		-		51		336		387
Other liabilities		-		-		1		1
Total liabilities	$	-	$	51	$	344	$	395

(1) Level 2 balances include commingled funds, which are comprised primarily of securities traded publicly on exchanges. Price quotes for the assets held by the funds are readily observable and available.
(2) Excludes deferred taxes on appreciation of investment value.
(3) Balances include the impact of netting adjustments of $214 million to Level 1. Includes natural gas for electric portfolio. (4) Balances include the impact of netting adjustments of $129 million to Level 2, and $53 million to Level 3. Includes natural gas for electric portfolio. (5) Balances include the impact of netting adjustments of $34 million to Level 3. Includes natural gas for core customers.

Fair Value Measurements at December 31, 2009
(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Money market investments	$	189	$	-	$	4	$	193
Nuclear decommissioning trusts
U.S. equity securities (1)		762		6		-		768
Non-U.S. equity securities		344		-		-		344
U.S. government and agency securities		653		51		-		704
Municipal securities		1		89		-		90
Other fixed income securities		-		108		-		108
Total nuclear decommissioning trusts (2)		1,760		254		-		2,014
Rabbi trusts
Equity securities		21		-		-		21
Life insurance contracts		60		-		-		60
Total rabbi trusts		81		-		-		81
Long-term disability trust
U.S. equity securities (1)		52		23		-		75
Corporate debt securities (1)		-		113		-		113
Total long-term disability trust		52		136		-		188
Total assets	$	2,082	$	390	$	4	$	2,476
Liabilities:
Dividend participation rights	$	-	$	-	$	12	$	12
Price risk management instruments
Electric (3)		2		73		157		232
Gas (4)		1		-		60		61
Total price risk management instruments		3		73		217		293
Other liabilities		-		-		3		3
Total liabilities	$	3	$	73	$	232	$	308


(1) Level 2 balances include commingled funds, which are comprised primarily of securities traded publicly on exchanges. Price quotes for the assets held by the funds are readily observable and available.
(2) Excludes taxes on appreciation of investment value.
(3) Balances include the impact of netting adjustments of $108 million to Level 1, $48 million to Level 2, and $19 million to Level 3. Includes natural gas for electric portfolio.
(4) Balances include the impact of netting adjustments of $13 million to Level 3. Includes natural gas for core customers.

PG&E Corporation
Fair Value Measurements at September 30, 2009
(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Money market investments (held by PG&E Corporation)	$	185	$	-	$	5	$	190
Nuclear decommissioning trusts
Equity securities		1,081		-		6		1,087
U.S. government and agency issues		661		52		-		713
Municipal bonds and other		-		183		-		183
Total nuclear decommissioning trusts (1)		1,742		235		6		1,983
Rabbi trusts-equity securities		76		-		-		76
Long-term disability trust
Equity securities		8		-		20		28
Corporate debt securities		-		-		101		101
Total long-term disability trust		8		-		121		129
Total assets	$	2,011	$	235	$	132	$	2,378
Liabilities:
Dividend participation rights	$	-	$	-	$	20	$	20
Price risk management instruments(2)		25		85		157		267
Other		-		-		4		4
Total liabilities	$	25	$	85	$	181	$	291

(1) Excludes deferred taxes on appreciation of investment value.
(2) Balances include the impact of netting adjustments of $76 million to Level 1, $33 million to Level 2, and $88 million to Level 3.

	PG&E Corporation Only						PG&E Corporation and the Utility
(in millions)	Money Market			Dividend Participation Rights			Price Risk Management Instruments			Nuclear Decommission-ing Trusts Equity Securities (1)		Long-Term Disability Equity Securities		Long-Term Disability Corp. Debt Securities		Other Liabilities			Total
Asset (Liability) Balance as of December 31, 2009	$	4		$	(12	)	$	(217	)	$	-	$	-	$	-	$	(3	)	$	(228	)
Realized and unrealized gains (losses):
Included in earnings		-			-			-			-		-		-		-			-
Included in regulatory assets and liabilities or balancing accounts		-			-			(119	)		-		-		-		2			(117	)
Purchases, issuances, and settlements		(4	)		5			-			-		-		-		-			1
Transfers into Level 3		-			-			-			-		-		-		-			-
Transfers out of Level 3		-			-			-			-		-		-		-			-
Asset (Liability) Balance as of March 31, 2010	$	-		$	(7	)	$	(336	)	$	-	$	-	$	-	$	(1	)	$	(344	)

(1) Excludes deferred taxes on appreciation of investment value.

·	The fair values of cash and cash equivalents, restricted cash and deposits, net accounts receivable, price risk management assets and liabilities, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at September 30, 2009 and December 31, 2008.

·	The fair values of the Utility’s fixed rate senior notes, fixed rate pollution control bond loan agreements, PG&E Corporation’s Convertible Subordinated Notes, PG&E Corporation’s fixed rate senior notes, and the ERBs issued by PERF were based on quoted market prices at September 30, 2009 and December 31, 2008.

	At September 30,				At December 31,				At March 31,				At December 31,
	2009				2008				2010				2009
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Debt (Note 4):
PG&E Corporation	$	597	$	1,061	$	280	$	739	$	597	$	1,070	$	597	$	1,096
Utility		8,690		9,528		8,740		9,134		9,240		9,727		9,240		9,824
Energy recovery bonds (Note 4)		1,310		1,357		1,583		1,564		1,120		1,176		1,213		1,269

	Maturity Date		Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Estimated (1) Fair Value
(in millions)
Nine months ended September 30, 2009
U.S. government and agency issues		2009-2038	$	648	$	66	$	(1	)	$	713
Municipal bonds and other		2009-2049		179		6		(2	)		183
Equity securities				546		543		(2	)		1,087
Total			$	1,373	$	615	$	(5	)	$	1,983

(1) Excludes deferred taxes on appreciation of investment value.

As of March 31, 2010	(in millions)
Less than 1 year	$	65
1–5 years		394
5–10 years		234
More than 10 years		210
Total maturities of debt securities	$	903

	Nine Months Ended September 30,			Year Ended December 31,
	2009			2008
(in millions)
Gross realized gains on sales of securities held as available-for-sale	$	24		$	30
Gross realized losses on sales of securities held as available-for-sale		(52	)		(142	)

(in millions)
Balance at December 31, 2009	$	946
Interest accrued		8
Less: Supplier Settlements		-
Balance at March 31, 2010	$	954

(in millions)
Balance at December 31, 2008	$	1,750
Interest accrued		45
Less: Supplier Settlements		(90	)
Less: August 26, 2009 payment		(700	)
Balance at September 30, 2009	$	1,005

(in millions)
2010	$	1,674
2011		2,260
2012		2,309
2013		2,307
2014		2,268
Thereafter		38,464
Total	$	49,282

(in millions)
Balance at December 31, 2008	$	27
Additional severance costs accrued		72
Less: Payments		(23	)
Balance at September 30, 2009	$	76

(in millions)
Balance at December 31, 2009	$	586
Additional remediation costs accrued:
Transfer to regulatory account for recovery		52
Amounts not recoverable from customers		5
Less: Payments		(30	)
Balance at March 31, 2010	$	613

·	$4943 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California;

·	$~~156~~180 million for remediation at the Utility’s natural gas compressor site located ~~in Topock, Arizona, near~~on the California ~~border;~~border, near Topock, Arizona;

·	$8684 million related to remediation at divested generation facilities;

·	$~~246~~124 million related to remediation costs for the Utility’s generation and other facilities and for third-party disposal ~~sites, and manufactured gas plant~~sites;

·	$132 million related to investigation and/or remediation costs at former MGP sites owned by the Utility or third parties (including those sites that are the subject of remediation orders by environmental agencies or claims by the current owners of the former ~~manufactured gas plant~~MGP sites); and

·	~~$60~~$50 million related to remediation ~~costs for fossil~~ decommissioning fossil-fueled sites.

·	The Outcome of Regulatory Proceedings and the Impact of Ratemaking ~~Mechanisms~~Mechanisms.~~. Most of~~ During 2010, the ~~Utility’s~~CPUC will determine the amount of revenue requirements ~~are set based on~~the Utility is authorized to recover from 2011 through 2013 for its ~~costs of service~~electric and natural gas distribution operations and its electric generation operations in ~~proceedings such as~~ the 2011 General Rate Case (“2011 GRC”) ~~filed with~~and from 2011 through 2014 for its natural gas transportation and storage services in the ~~CPUC~~Gas Transmission and Storage Rate Case. In addition, in the Utility’s most recent annual transmission owner (“TO”) rate ~~cases filed with~~case, the ~~FERC. (See “Regulatory Matters” below.) The Utility intends to file its 2011-2013 GRC application with~~FERC will determine the ~~CPUC before the end~~amount of ~~2009 to request an increase in authorized~~ electric ~~distribution, gas distribution, and electric generation revenue requirements. On September 18, 2009,~~transmission revenues the Utility ~~requested~~can recover beginning in March 2011. The decisions issued in the ~~CPUC to~~three associated r ate cases will determine the ~~rates, and terms and conditions~~majority of the Utility’s ~~gas transmission~~base revenue requirements for 2011 and ~~storage services beginning January 1, 2011. The~~future years. In addition, the Utility ~~also files separate applications requesting~~has requested the CPUC or the FERC to authorize additional base revenue requirements for specific capital expenditure projects such as new power plants, new or upgraded natural gas or electric transmission facilities, the installation of an advanced metering infrastructure, and ~~reliability or system~~other infrastructure improvements. (See “Capital Expenditures” below.) The Utility’s revenues will also be affected by incentive ratemaking, such as the CPUC’s customer energy efficiency shareholder incentive mechanism. In addition, the CPUC has authorized the Utility to recover 100%outcome of ~~its reasonable electric fuel and energy procurement costs and has established a timely rate adjustment mechanism to recover such costs. As a result, the Utility’s revenues and costs~~these regulatory proceedings can be affected by ~~volatility in~~many factors, including general economic conditions, the ~~prices~~level of ~~natural gas~~rates, and ~~electricity. (See “Risk Management Activities” below.)~~political and regulatory policies.

·	~~Capital Structure and Return on Common Equity.~~ The Utility’s current CPUC-authorized capital structure includes a 52% common equity component, which will remain in effect through 2012. The CPUC has authorized the Utility to set rates targeted to earn an ROE of 11.35% on the equity component of its electric and natural gas distribution and electric generation rate base through 2010. The Utility’s cost of capital for 2011 and 2012 will change only if the annual adjustment mechanism established by the CPUC is triggered. If the adjustment is triggered, the Utility’s authorized cost of capital would be adjusted effective January 1 of the following year. The Utility can also apply for an adjustment to either its capital structure or its cost of capital at any time in the event of extraordinary circumstances. (See “Regulatory Matters” below.)

·	The Ability of the Utility to Control Costs While Improving Operational Efficiency and Reliability. The Utility’s revenue requirements in general rate cases and TO rate cases are generally set at a level to allow the Utility the opportunity to recover its basic forecasted operating expenses as well as to earn ~~an ROE~~a return on equity (“ROE”) and recover depreciation, tax, and interest expense associated with authorized capital expenditures. Differences in the amount or timing of forecasted and actual operating expenses and capital expenditures can affect the Utility’s ability to earn its ~~authorized~~CPUC-authorized rate of return and the amount of PG&E Corporation’s income available for common shareholders. In addition, the Utility ma y incur higher than anticipated operating expenses than provided for in the last general rate case. The Utility continuously re-prioritizes spending and seeks to achieve sustainable operational efficiencies to maximize its ability to earn its authorized return while maintaining and improving operational safety and reliability. (See “Results of Operations” below.) The Utility also seeks to make the amount and timing of its capital expenditures consistent with ~~budgeted~~forecasted amounts and timing. When capital expenditures are higher than authorized levels, the Utility incurs associated depreciation, property tax, and interest expense but does not recover revenues to fully offset these expenses or earn an ROE until the increased capital expenditures are added to rate base in future rate cases. Items that could cause higher expenses than provided for in the last GRC primarily relate to the Utility’s efforts to maintain its aging electric and natural gas systems infrastructure, to improve the reliability and safety of its electric and natural gas system, and to improve its information technology infrastructure, support, and security. The Utility continually seeks to achieve operational efficiencies and improve reliability while creating future sustainable cost savings to offset these higher anticipated expenses. In connection with these efforts, the Utility has accrued severance costs, including severance costs related to the reduction of approximately 2% of the Utility’s workforce, in the three months ended September 30, 2009. (See ~~“Results of Operations”~~“Capital Expenditures” below.)

·	~~Timing~~Capital Structure and ~~Amount~~Financing. The CPUC has authorized a capital structure for the Utility’s electric and natural gas distribution and electric generation rate base that consists of ~~Debt~~52% common equity and ~~Equity Financing.~~48% debt and preferred stock. This authorized capital structure will remain in effect through 2012. The CPUC also has authorized the Utility to earn a rate of return on each component of its capital structure, including an ROE of 11.35%. These rates will remain in effect through 2010. The rates for 2011 and 2012 are subject to an annual adjustment mechanism that will be triggered if the 12-month October-through-September average yield for the applicable Moody’s Investors Service utility bond index increases or decreases by mo re than 1% as compared to the applicable benchmark. The amount of the Utility’s authorized equity earnings is determined by the 52% equity component, the 11.35% ROE, and the aggregate amount of rate base authorized by the CPUC. The rate of return that the Utility earns on its FERC-jurisdictional rate base is not specifically authorized, but rates are designed to allow the Utility to earn a reasonable rate of return. The Utility’s actual equity earnings could be more or less based on a number of factors, including the timing and amount of operating costs and capital expenditures. The CPUC periodically authorizes the aggregate amount of long-term debt and short-term debt that the Utility may issue and authorizes the Utility to recover its related debt financing costs. The timing and amount of the Utility’s future financing ~~needs~~ will depend on various factors, ~~including the conditions~~as discussed in ~~the capital markets, the amount~~“Liquidity and ~~timing of scheduled principal and interest payments on long-term debt, the amount and timing of planned capital expenditures, and the amount and timing of interest payments related~~Financial Resources” below. PG& amp;E Corporation regularly contributes equity to the remaining disputed claims that were made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”). (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.) The amount of the Utility’s short-term financing will vary depending on the level of operating cash flows, seasonal demand for electricity and natural gas, volatility in electricity and natural gas prices, and collateral requirements related to price risk management activities, among other factors. In orderUtility to maintain the Utility’s CPUC-authorized capital ~~structure,~~structure. PG&E Corporation ~~contributed $688 million of~~may issue debt or equity in the future to ~~the Utility during 2009. The timing and amount of future~~fund these equity ~~contributions to the Utility will affect the timing and amount of any future equity or debt issuances by PG&E Corporation. (See “Liquidity and Financial Resources” below.)~~contributions.