10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 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 or Organization	IRS Employer Identification Number
1-12609	PG&E CORPORATION	California	94-3234914
1-2348	PACIFIC GAS AND ELECTRIC COMPANY	California	94-0742640

One Market, Spear Tower Suite 2400 San Francisco, California 94105 (Address of principal executive offices) (Zip Code)	77 Beale Street, P.O. Box 770000 San Francisco, California 94177 (Address of principal executive offices) (Zip Code)
(415) 267-7000 (Registrant’s telephone number, including area code)	(415) 973-7000 (Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
PG&E Corporation: Common Stock, no par value	New York Stock Exchange
Pacific Gas and Electric Company: First Preferred Stock, cumulative, par value $25 per share:	NYSE Amex Equities
Redeemable: 5% Series A, 5%, 4.80%, 4.50%, 4.36%
Nonredeemable: 6%, 5.50%, 5%

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:

PG&E Corporation	Yes  x    No  ¨
Pacific Gas and Electric Company	Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:

PG&E Corporation	Yes  ¨    No  x
Pacific Gas and Electric Company	Yes  ¨    No  x

Indicate by check mark whether the 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) has been subject to such filing requirements for the past 90 days.

PG&E Corporation	Yes  x    No  ¨
Pacific Gas and Electric Company	Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

PG&E Corporation	Yes  x    No  ¨
Pacific Gas and Electric Company	Yes  ¨    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K:

PG&E Corporation	x
Pacific Gas and Electric Company	x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act). (Check one):

PG&E Corporation	Pacific Gas and Electric Company
Large accelerated filer x	Large accelerated filer  ¨
Accelerated filer  ¨	Accelerated filer  ¨
Non-accelerated filer  ¨	Non-accelerated filer  x
Smaller reporting company  ¨	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  ¨    No  x
Pacific Gas and Electric Company	Yes  ¨    No  x

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2010, the last business day of the most recently completed second fiscal quarter:

PG&E Corporation Common Stock	$16,024 million
Pacific Gas and Electric Company Common Stock	Wholly owned by PG&E Corporation

Common Stock outstanding as of February 7, 2011:

PG&E Corporation:	396,258,407 shares
Pacific Gas and Electric Company:	264,374,809 shares (wholly owned by PG&E Corporation)

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:

Designated portions of the combined 2009 Annual Report to Shareholders Part I (Items 1 and 1.A.), Part II (Items 5, 6, 7, 7A, 8 and 9A)

Designated portions of the Joint Proxy Statement relating to the 2010 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14)

TABLE OF CONTENTS

			Page
	Units of Measurement			iii
PART I
Item 1.		Business		1
		General		1
		Corporate Structure and Business		1
		Corporate and Other Information		1
		Employees		1
		Pending Investigations		1
		Cautionary Language Regarding Forward-Looking Statements		2
		PG&E Corporation’s Regulatory Environment		4
		Federal Energy Regulation		4
		State Energy Regulation		4
		The Utility’s Regulatory Environment		5
		Federal Energy Regulation		5
		State Energy Regulation		6
		Other Regulation		7
		Franchise Agreements		7
		Competition		8
		Competition in the Electricity Industry		8
		Competition in the Natural Gas Industry		10
		Ratemaking Mechanisms		11
		Overview		11
		Electricity and Natural Gas Distribution and Electricity Generation Operations		12
		General Rate Cases		12
		Attrition Rate Adjustments		12
		Cost of Capital Proceedings		12
		Rate Recovery of Costs of New Electricity Generation Resources		13
		Overview		13
		Costs Incurred Under New Power Purchase Agreements		13
		Costs of Utility-Owned Generation Resource Projects		14
		DWR Electricity and DWR Revenue Requirements		14
		Electricity Transmission		14
		Transmission Owner Rate Cases		15
		Natural Gas		15
		The Gas Accord		15
		Biennial Cost Allocation Proceeding		16
		Natural Gas Procurement		16
		Interstate and Canadian Natural Gas Transportation		16
		Electric Utility Operations		17
		Electricity Resources		17
		Owned Generation Facilities		18
		DWR Power Purchases		19
		Third-Party Power Purchase Agreements		19
		Renewable Generation Resources		20
		Future Long-Term Generation Resources		21
		Electricity Transmission		21
		Electricity Distribution Operations		22
		2010 Electricity Deliveries		23
		Electricity Distribution Operating Statistics		24
		Natural Gas Utility Operations		25
		Natural Gas System		25
		2010 Natural Gas Deliveries		26
		Natural Gas Operating Statistics		27

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		Natural Gas Supplies	28
		Gas Gathering Facilities	28
		Interstate and Canadian Natural Gas Transportation Services Agreements	28
		Energy Efficiency, Public Purpose and Other Programs	29
		Energy Efficiency Programs	30
		Demand Response Programs	30
		Self-Generation Incentive Program and California Solar Initiative	30
		Low-Income Energy Efficiency Programs and California Alternate Rates for Energy	30
		Environmental Matters	31
		General	31
		Air Quality and Climate Change	31
		Emissions Data	33
		Total 2009 GHG Emissions by Source Category	33
		Benchmarking Greenhouse Gas Emissions for Delivered Electricity	34
		Emissions Data for Utility-Owned Generation	34
		Water Quality	34
		Hazardous Waste Compliance and Remediation	35
		Generation Facilities	36
		Former Manufactured Gas Plant Sites	36
		Third-Party Owned Disposal Sites	37
		Natural Gas Compressor Stations	37
		Recovery of Environmental Remediation Costs	38
		Nuclear Fuel Disposal	38
		Nuclear Decommissioning	38
		Endangered Species	39
		Electric and Magnetic Fields	39
Item 1A.		Risk Factors	40
Item 1B.		Unresolved Staff Comments	40
Item 2.		Properties	40
Item 3.		Legal Proceedings	40
		Diablo Canyon Power Plant	40
		Litigation Related to the San Bruno Accident	41
		Pending Investigations of the San Bruno and Rancho Cordova Accidents	42
Item 4.		[removed and reserved]	42
Executive Officers of the Registrants			42
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		45
Item 6.	Selected Financial Data		46
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		46
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		46
Item 8.	Financial Statements and Supplementary Data		46
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		46
Item 9A.	Controls and Procedures		46
Item 9B.	Other Information		47
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		47
Item 11.	Executive Compensation		48
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		48
Item 13.	Certain Relationships and Related Transactions, and Director Independence		49
Item 14.	Principal Accountant Fees and Services		49
PART IV
Item 15.	Exhibits and Financial Statement Schedules		49
	Signatures		59
	Report of Independent Registered Public Accounting Firm		61
	Financial Statement Schedules		62

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UNITS OF MEASUREMENT

1 Kilowatt (kW)	=	One thousand watts
1 Kilowatt-Hour (kWh)	=	One kilowatt continuously for one hour
1 Megawatt (MW)	=	One thousand kilowatts
1 Megawatt-Hour (MWh)	=	One megawatt continuously for one hour
1 Gigawatt (GW)	=	One million kilowatts
1 Gigawatt-Hour (GWh)	=	One gigawatt continuously for one hour
1 Kilovolt (kV)	=	One thousand volts
1 MVA	=	One megavolt ampere
1 Mcf	=	One thousand cubic feet
1 MMcf	=	One million cubic feet
1 Bcf	=	One billion cubic feet
1 MDth	=	One thousand decatherms

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PART I

Item  1. Business

General

Corporate Structure and Business

PG&E Corporation, incorporated in California in 1995, 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 the businesses of electricity and natural gas distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997.

The Utility served approximately 5.2 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2010. The Utility had approximately $45.7 billion in assets at December 31, 2010 and generated revenues of $13.8 billion in 2010. Its revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). In addition, the Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.

Corporate and Other Information

The principal executive office of PG&E Corporation is located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive office of the Utility is located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. PG&E Corporation and the Utility file or furnish various reports with the Securities and Exchange Commission (“SEC”). These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (“1934 Act”), are available free of charge on both PG&E Corporation’s website, www.pgecorp.com, and the Utility’s website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC . The information contained on these websites is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report.

This is a combined Annual Report on Form 10-K of PG&E Corporation and the Utility and includes information incorporated by reference from the joint Annual Report to Shareholders for the year ended December 31, 2010 (“2010 Annual Report”) and the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders.

Employees

At December 31, 2010, PG&E Corporation and its subsidiaries had 19,424 regular employees, including 19,381 regular employees of the Utility. Of the Utility’s regular employees, 12,236 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO (“IBEW”); the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC (“ESC”); and the Service Employees International Union, Local 24/7 (“SEIU”). One IBEW collective bargaining agreement expires on December 31, 2011 and the other expires on December 31, 2015. The ESC collective bargaining agreement expires on December 31, 2011. The SEIU collective bargaining agreement expires on July  31, 2012.

Pending Investigations

Both the National Transportation Safety Board (“NTSB”) and the CPUC have begun investigations of the September 9, 2010 rupture of an underground 30-inch natural gas transmission pipeline (line 132) owned and operated by the Utility in a residential area located in the City of San Bruno, California (the “San Bruno accident”).

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The ensuing explosion and fire resulted in the deaths of eight people and injuries to numerous individuals. At least thirty-four houses were destroyed and many additional houses were damaged. The NTSB has not yet determined the cause of the pipeline rupture. The NTSB has publicly issued some preliminary reports and has announced that it will hold fact-finding hearings on March 1-3, 2011 to learn more about the San Bruno accident and important safety issues.

Various lawsuits have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility. (See Item 3. Legal Proceedings, below.) In addition, on November 19, 2010, the CPUC began a formal investigation of the December 24, 2008 natural gas explosion in a house located in Rancho Cordova, California that resulted in one death, injuries to several people, and property damage (the “Rancho Cordova accident”). For more information about these investigations and related matters see “Pending Investigations” and “Risk Factors” in the 2010 Annual Report.

Cautionary Language Regarding Forward-Looking Statements

This combined Annual Report on Form 10-K, including the information incorporated by reference from the 2010 Annual Report and the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations and projections about future events, and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated environmental remediation, tax, and other liabilities, estimates and assumptions used in PG&E Corporation’s and the Utility’s critical accounting policies, the anticipated outcome of various regulatory, governmental, and legal proceedings, estimated losses and insurance recoveries associated with the San Bruno accident, estimated future cash flows, and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim,” “may,” “might,” “should,” “would,” “could,” “goal,” “potential” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

• the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within authorized levels and timely recover its costs through rates;

• the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigations by the NTSB and CPUC into the cause of the San Bruno accident and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory, the CPUC investigation of the Rancho Cordova accident, whether the Utility incurs civil or criminal penalties as a result of these proceedings whether the Utility is required to incur additional costs for third-party liability claims or to comply with regulatory or legislative mandates which costs the Utility is unable to recover through rates or insurance, and whether the Utility incurs third-party liabilities or other costs in connection with service disruptions that may occur as the Utility complies with regulatory orders to decrease pressure in its natural gas transmission system;

• reputational harm that PG&E Corporation and the Utility may suffer depending on the outcome of the various investigations, including those by the NTSB and the CPUC, the outcome of civil litigation, and the extent to which civil or criminal proceedings may be pursued by regulatory or governmental agencies;

• the adequacy and price of electricity and natural gas supplies the extent to which the Utility can manage and respond to the volatility of electricity and natural gas prices, and the ability of the Utility and its counterparties to post or return collateral;

• explosions, fires, accidents, mechanical breakdowns, the disruption of information technology and systems, human errors, and similar events that may occur while operating and maintaining an electric and natural gas system in a large service territory with varying geographic conditions that can cause unplanned outages, reduce generating output, damage the Utility’s assets or operations, subject the Utility to third-party claims for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utility;

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• the impact of storms, earthquakes, floods, drought, wildfires, disease, and similar natural disasters, or acts of terrorism or vandalism, that affect customer demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies;

• the potential impacts of climate change on the Utility’s electricity and natural gas businesses;

• changes in customer demand for electricity (“load”) and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology that include the development of alternative technologies that enable customers to increase their reliance on self-generation, or other reasons;

• the occurrence of unplanned outages at the Utility’s two nuclear generating units at Diablo Canyon Power Plant (“Diablo Canyon”), the availability of nuclear fuel, the outcome of the Utility’s application to renew the operating licenses for Diablo Canyon, and potential changes in laws or regulations promulgated by the NRC or environmental agencies with respect to the storage of spent nuclear fuel, security, safety, cooling water intake, or other matters associated with the operations at Diablo Canyon;

• whether the Utility earns incentive revenues or incurs obligations under incentive ratemaking mechanisms, such as the CPUC’s incentive ratemaking mechanism relating to energy savings achieved through implementation of the utilities’ customer energy efficiency programs;

• the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies;

• whether the Utility can successfully complete its program to install advanced meters for its electric and natural gas customers, allay customer concerns about the new metering technology, and integrate the new meters with its customer billing and other systems while also implementing the system design changes necessary to accommodate retail electric rates based on dynamic pricing (i.e., electric rates that can vary with the customer’s time of use and are more closely aligned with wholesale electricity prices) by the CPUC’s due dates;

• how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company and the extent to which the interpretation or enforcement of these conditions has a material impact on PG&E Corporation;

• the extent to which PG&E Corporation or the Utility incurs costs in connection with third-party claims or litigation, including those arising from the San Bruno accident, that are not recoverable through insurance, rates, or from other third parties;

• the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;

• the impact of environmental laws and regulations addressing the reduction of carbon dioxide and other greenhouse gases (“GHG”), water, the remediation of hazardous waste, and other matters, and whether the Utility is able to recover the costs of compliance with such laws, including the cost of emission allowances and offsets that the Utility may incur under federal or state cap and trade regulations;

• the loss of customers due to various forms of bypass and competition, including municipalization of the Utility’s electric distribution facilities, increasing levels of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which permits cities and counties to purchase and sell electricity for their local residents and businesses; and

• the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations, such as The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010.

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For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see the discussion in the section entitled “Risk Factors” in the 2010 Annual Report. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

PG&E Corporation’s Regulatory Environment

Federal Energy Regulation

As a public utility holding company, PG&E Corporation is subject to the requirements of the Energy Policy Act of 2005 (“EPAct”). Among its key provisions, the EPAct repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). Under PUHCA 2005, public utility holding companies fall principally under the regulatory oversight of the FERC. PG&E Corporation and its subsidiaries are exempt from all requirements of PUHCA 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes. These books and records provisions are largely duplicative of other provisions under the Federal Power Act of 1935 and state law.

State Energy Regulation

PG&E Corporation is not a public utility under California law. The CPUC has authorized the formation of public utility holding companies subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that:

• the Utility cannot guarantee any obligations of PG&E Corporation without prior written consent from the CPUC;

• the Utility’s dividend policy must be established by the Utility’s Board of Directors as though the Utility were a stand-alone utility company;

• the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation’s Board of Directors (known as the “first priority” condition); and

• the Utility must maintain on average its CPUC-authorized utility capital structure, although it can request a waiver of this condition if an adverse financial event reduces the Utility’s common equity component by 1% or more.

The CPUC also has adopted complex and detailed rules governing transactions between California’s electricity and gas utilities and certain of their affiliates. The rules address the use of the utilities’ names and logos by their affiliates, the separation of utilities and their affiliates, provision of utility information to affiliates, and energy procurement-related transactions between the utilities and their affiliates. The rules also:

• prohibit each utility from engaging in certain practices that would discriminate against energy service providers that compete with that utility’s affiliates;

• emphasize that the holding company may not aid or abet a utility’s violation of the rules or act as a conduit to provide confidential utility information to an affiliate;

• require prior CPUC approval before the utility can contract with an affiliate for resource procurement (e.g., electricity or gas), except in blind transactions where the identity of the other party is not known until the transaction is consummated;

• require certain key officers to provide annual certifications of compliance with the affiliate rules;

• prohibit certain key officers from serving in the same position at both the utility and the holding company (unless otherwise permitted by the CPUC), or, in the alternative, prohibit the sharing of lobbying, regulatory relations and certain legal services (except for legal services necessary to the provision of permitted shared services);

• require the utility to obtain a “nonconsolidation opinion” indicating that it would not be consolidated into a bankruptcy of its holding company; and

• make the CPUC’s Energy Division responsible for hiring independent auditors to conduct biennial audits to verify that the utility is in compliance with the affiliate rules.

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The CPUC has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations.

The Utility’s Regulatory Environment

Various aspects of the Utility’s business are subject to a complex set of energy, environmental and other laws, regulations, and regulatory proceedings at the federal, state, and local levels. In addition to enacting PUHCA 2005 to replace the Public Utility Holding Company Act of 1935, as discussed above, the EPAct significantly amended various federal energy laws applicable to electric and natural gas markets, including the Federal Power Act of 1935, the Natural Gas Act of 1938, and the Public Utility Regulatory Policies Act of 1978 (“PURPA”).

This section and the “Ratemaking Mechanisms” section below summarize some of the more significant laws, regulations, and regulatory mechanisms affecting the Utility. These summaries are not an exhaustive description of all the laws, regulations, and regulatory proceedings that affect the Utility. The energy laws, regulations, and regulatory proceedings may change or be implemented or applied in a way that the Utility does not currently anticipate. For discussion of specific pending regulatory proceedings that are expected to affect the Utility, see “Regulatory Matters” and “Pending Investigations” in the 2010 Annual Report.

Federal Energy Regulation

The FERC. The FERC regulates the transmission and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale in interstate commerce. The FERC also regulates interconnections of transmission systems with other electric systems and generation facilities, tariffs and conditions of service of regional transmission organizations, including the California Independent System Operator (“CAISO”), and the terms and rates of wholesale electricity sales. The FERC has authority to impose penalties of up to $1,000,000 per day for violation of certain federal statutes, including the Federal Power Act of 1935 and the Natural Gas Act of 1938, and for violations of FERC-approved regulations. The FERC has jurisdiction over the Utility’s electricity transmission revenue requirements and rates, the licensing of substantially all of the Utility’s hydroelectric generation facilities, and the interstate sale and transportation of natural gas.

Electric Reliability Standards; Development of Transmission Grid. The FERC has the responsibility to approve and enforce mandatory standards governing the reliability of the nation’s electricity transmission grid, including standards to protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches, to prevent market manipulation, and to supplement state transmission siting efforts in certain electric transmission corridors that are determined to be of national interest. The FERC certified the North American Electric Reliability Corporation (“NERC”) as the nation’s Electric Reliability Organization under the EPAct. The NERC is responsible for developing and enforcing electric reliability standards, subject to FERC approval. The FERC also has approved a delegation agreement under which the NERC has delegated enforcement authority for the geographic area known as the Western Interconnection to the Western Electricity Coordinating Council (“WECC”). The Utility must self-certify compliance to the WECC on an annual basis and the compliance program encourages self-reporting of violations. WECC staff, with participation by the NERC and the FERC, will also perform a regular compliance audit of the Utility every three years. In addition, the WECC and the NERC may perform spot checks or other interim audits, reports, or investigations. Under FERC authority, the WECC, NERC, and/or FERC may impose penalties up to $1,000,000 per day per violation.

The FERC also has issued rules on electric transmission pricing reforms designed to promote needed investment in energy infrastructure, to reduce transmission congestion, and to require transmission organizations with organized electricity markets to make long-term firm transmission rights available to load-serving entities, so these entities can enter into long-term transmission service arrangements without being exposed to unhedged congestion cost risk. In addition, pursuant to FERC orders, the CAISO is responsible for providing open access electricity transmission service on a non-discriminatory basis, planning transmission system additions, and ensuring the maintenance of adequate reserves of generation capacity.

Prevention of Market Manipulation. The FERC has broad authority to police and penalize the exercise of market power or behavior intended to manipulate prices paid in FERC-jurisdictional transactions. The FERC has

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adopted rules to prohibit market manipulation, modeling its new rules on SEC Rule 10b-5, which prohibits fraud and manipulation in the purchase or sale of securities. Under the FERC’s regulations, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas, electric energy, or transportation/transmission services subject to the jurisdiction of the FERC (1) to use or employ any device, scheme, or artifice to defraud, (2) to make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (3) to engage in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any person.

QF Regulation. Under PURPA, electric utilities are required to purchase energy and capacity from independent power producers with generation facilities that meet the statutory definition of a qualifying facility (“QF”). (QFs primarily include co-generation facilities that produce combined heat and power (“CHP”) and renewable generation facilities.) To implement the purchase requirements of PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with QFs and approved the applicable terms, conditions, prices, and eligibility requirements. The EPAct significantly amended the purchase requirements of PURPA. As amended, Section 210(m) of PURPA authorizes the FERC to terminate the obligation of an electric utility to purchase the electricity offered to it by a QF (under a new contract or obligation), if the FERC finds that the QF has nondiscriminatory access to one of three defined categories of competitive wholesale electricity markets. The statute permits a termination of such obligations on a “service territory-wide basis.” For more information about the Utility’s QF agreements, see “Electricity Resources – Third-Party Power Purchase Agreements,” below.

The Nuclear Regulatory Commission. The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay (“Humboldt Bay Unit 3”). NRC regulations require extensive monitoring and review of the safety, radiological, environmental, and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.

State Energy Regulation

California Legislature. The Utility’s operations have been significantly affected by statutes passed by the California legislature, including laws related to electric industry restructuring, the 2000-2001 California energy crisis, electric resource adequacy, renewable energy resources, power plant siting and permitting, and GHG emissions and other environmental matters.

The CPUC. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms. The CPUC has jurisdiction to set the rates, terms, and conditions of service for the Utility’s electricity distribution, electricity generation, natural gas distribution, and natural gas transportation and storage services in California. The CPUC also has jurisdiction over the Utility’s issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility’s electricity and natural gas retail customers, rate of return, rates of depreciation, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service. The CPUC also enforces law that sets forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas gathering, transmission, and distribution piping systems, and for the safe operation of such lines and equipment.

Ratemaking for retail sales from the Utility’s generation facilities is under the jurisdiction of the CPUC. To the extent that this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC has general jurisdiction over most of the Utility’s operations, and regularly reviews the Utility’s performance, using measures such as the frequency and duration of outages. The CPUC also conducts investigations into various matters, such as deregulation, competition, and the environment, in order to determine its future policies.

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PG&E Corporation and the Utility entered into a settlement agreement with the CPUC on December 19, 2003, to resolve the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that had been pending in the U.S. Bankruptcy Court for the Northern District of California (“Bankruptcy Court”) since April 2001, referred to as the Chapter 11 Settlement Agreement. The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters to restore the Utility’s financial health and enable it to emerge from Chapter 11. The terms of the Chapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11, which became effective on April 12, 2004. The Bankruptcy Court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation, or enforcement of the Chapter 11 Settlement Agreement, in addition to other matters.

The California Energy Resources Conservation and Development Commission. The California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission (“CEC”), is the state’s primary energy policy and planning agency. The CEC is responsible for licensing of all thermal power plants over 50 MW, overseeing funding programs that support public interest energy research, advancing energy science and technology through research, development and demonstration, and providing market support to existing, new, and emerging renewable technologies. In addition, the CEC is responsible for forecasting future energy needs used by the CPUC in determining the adequacy of the utilities’ electricity procurement plans.

The California Air Resources Board. The California Air Resources Board (“CARB”) is the state agency charged with setting and monitoring greenhouse gas (“GHG”) and other emission limits. The CARB also is responsible for adopting and enforcing regulations to meet California’s landmark law, the California Global Warming Solutions Act of 2006 (“AB 32”), which requires the gradual reduction of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. (For more information see “Environmental Matters — Air Quality and Climate Change” below.)

Other Regulation

The Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utility’s generation facilities, electricity transmission lines, natural gas transportation pipelines, and gas compressor station facilities. These permits include discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses. Some licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. (For more information, see “Environmental Matters — Water Quality” below.)

The Utility also is subject to regulations adopted by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that is within the United States Department of Transportation. The PHMSA develops and enforces regulations for the safe, reliable, and environmentally sound operation of the nation’s pipeline transportation system and the shipment of hazardous materials. The CPUC also is authorized to enforce the federal pipeline safety standards, as well as state pipeline safety requirements, through penalties and/or injunctive relief.

The NTSB is an independent federal agency that is authorized to investigate pipeline accidents and certain transportation accidents that involve fatalities, substantial property damage, or significant environmental damage. The NTSB is currently investigating the San Bruno accident. (See Item 3. Legal Proceedings, below and “Pending Investigations” in the 2010 Annual Report for more information.)

Franchise Agreements

The Utility has over 520 franchise agreements with various cities and counties that permit the Utility to install, operate, and maintain the Utility’s electric and natural gas facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. In

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addition, charter cities can negotiate their fees. In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date. The Utility has several franchise agreements that have a specified term, including an agreement with a large charter city. The franchise agreements generally require that the Utility install and maintain the electric and gas facilities in compliance with regulations adopted by cities and counties in the exercise of their police powers relating to the use of the public streets. The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations, and licenses, the Utility has rights to occupy and/or use public property for the operation of the Utility’s business and to conduct certain related operations.

Competition

Historically, energy utilities operated as regulated monopolies within service territories in which they were essentially the sole suppliers of natural gas and electricity services. These utilities owned and operated all of the businesses and facilities necessary to generate, transport, and distribute energy. Services were priced on a combined, or bundled, basis, with rates charged by the energy companies designed to include all the costs of providing these services. Under traditional cost-of-service regulation, the utilities undertook a continuing obligation to serve their customers, in return for which the utilities were authorized to charge regulated rates sufficient to recover their costs of service, including timely recovery of their operating expenses and a reasonable return on their invested capital. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices.

In recent years, legislative and regulatory changes have brought competition to certain aspects of the energy industry, primarily the commodity components—the supply of electricity and natural gas to customers. Regulators and legislators, to varying degrees, have required utilities to separate (or “unbundle”) the prices of the energy commodities and the rates for utility services in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.

Competition in the Electricity Industry

Federal. At the federal level, many provisions of the EPAct support the development of competition in the wholesale electric market. The EPAct has directed the FERC to develop rules to encourage fair and efficient competitive markets by employing best practices in market rules and reducing barriers to trade between markets and among regions. The EPAct also gives the FERC authority to prevent accumulation and exercise of market power by assuring that proposed mergers and acquisitions of public utility companies and their holding companies are in the public interest and by addressing market power in jurisdictional wholesale markets through its new powers to establish and enforce rules prohibiting market manipulation.

Even before the passage of the EPAct, the FERC’s policies supported the development of a competitive electricity generation industry. FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities’ transmission grids. Order 888 requires all public utilities that own, control, or operate facilities used for transmitting electric energy in interstate commerce to have on file an open access non-discriminatory transmission tariff (“OATT”) that contains minimum terms and conditions of non-discriminatory service. The FERC’s subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations, and advanced the view that a regulated unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. On February 16, 2007, the FERC issued Order 890, which is designed to: (1) strengthen the form of the OATT adopted in Order 888 to ensure that tariffs achieve their original purpose of remedying undue discrimination, (2) provide greater specificity in the form of the OATT to reduce opportunities for undue discrimination and facilitate the FERC’s enforcement, and (3) increase transparency in the rules applicable to planning and use of the transmission system.

The FERC also has issued rules on the interconnection of generators to require regulated transmission providers, such as the Utility or the CAISO, to use standard interconnection procedures and a standard agreement for generator interconnections. These rules are intended to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and standardizing interconnection procedures, and encourage needed investment in generation and transmission. Under the rules and associated tariffs,

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a new generator is required to pay for the transmission system upgrades needed in order to interconnect the generator. The generator will be reimbursed over a five-year period after the power plant achieves commercial operation. The cost of the network upgrades is then recovered by the regulated transmission provider in its overall transmission rates.

On June 17, 2010, the FERC issued a notice of proposed rulemaking and established a proceeding to examine, among other issues, whether to change the FERC’s existing policy that provides incumbent traditional public utilities a “right of first refusal” to own, construct, and operate transmission facilities within their respective service territories. The rules that the FERC adopts in this proceeding may introduce additional competition from merchant or independent transmission project developers for the construction of certain transmission facilities that do not exist today.

State. At the state level, California Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry beginning in 1998 to allow customers of the California investor-owned electric utilities to purchase energy from a service provider other than the regulated utilities (the ability to choose an energy provider is referred to as “direct access”). Assembly Bill 1890 established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity through transactions conducted through the Power Exchange (“PX”). Following the 2000-2001 California energy crisis, the PX filed a petition for bankruptcy protection and now operates solely to reconcile remaining refund amounts owed and to make compliance filings as required by the FERC in the California refund proceeding, which is still pending at the FERC. (For information about the status of the California refund proceeding and the remaining disputed claims made by power suppliers in the Utility’s Chapter 11 proceeding, see Note 13 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.)

California Assembly Bill 1X authorized the California Department of Water Resources (“DWR”), beginning in February 1, 2001, to purchase electricity and sell that electricity directly to the utilities’ retail customers. Assembly Bill 1X requires the utilities to deliver electricity purchased by the DWR under the contracts and to act as the DWR’s billing and collection agent. To ensure that the DWR recovers the costs that it incurs under its power purchase contracts, the CPUC suspended direct access on September 20, 2001, but allowed existing direct access customers to continue being served by alternative energy service providers. As authorized by California Senate Bill 695, enacted on October 11, 2009, the CPUC has adopted a plan to reopen 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.

Assembly Bill 1890 also provided for the establishment of the CAISO, as a nonprofit public benefit corporation, to operate and control the state-wide electricity transmission grid and ensure efficient use and reliable operation of the transmission grid. On April 1, 2009, the CAISO implemented new day-ahead, hour-ahead, and real-time wholesale electricity markets subject to bid caps that increase over time, as part of the implementation of the CAISO’s Market Redesign and Technology Upgrade initiative (“MRTU”). Market participants, including load-serving entities like the Utility, are permitted to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market by acquiring congestion revenue rights.

In addition, the Utility’s customers may, under certain circumstances, obtain power from a “community choice aggregator” instead of from the Utility. California Assembly Bill 117, enacted in 2002, permits cities and counties to purchase and sell electricity for their local residents and businesses once they have registered as community choice aggregators. Under Assembly Bill 117, the Utility continues to provide distribution, metering, and billing services to the community choice aggregators’ customers and remains the electricity provider of last resort for those customers. Assembly Bill 117 provides that a community choice aggregator can procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. The CPUC has adopted rules to implement community choice aggregation, including the imposition of a surcharge on retail

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end-users of the community choice aggregator to prevent a shifting of costs to customers of a utility who receive bundled services and allowing a community choice aggregator to start service in phases. Assembly Bill 117 also authorized the Utility to recover from each community choice aggregator any costs of implementing the program that are reasonably attributable to the community choice aggregator, and to recover from all customers any costs of implementing the program not reasonably attributable to a community choice aggregator.

In some circumstances, governmental entities such as cities and irrigation districts, which have authority under the state constitution or state statute to provide retail electric service, seek to acquire the Utility’s distribution facilities. For example South San Joaquin Irrigation District (“SSJID”) has applied to San Joaquin County Local Agency Formation Commission for the authority to provide electric distribution service in and around the cities of Manteca, Ripon and Escalon. SSJID has indicated that, if it receives the requested authority, it will seek to acquire the Utility’s distribution facilities, either under a consensual transaction, or via eminent domain.

It is also possible that technological developments, such as distributed generation and the increased use of electric vehicles, could pose competitive challenges for traditional utilities. In July 2010, the CPUC found that although the California Legislature did not intend that the CPUC regulate providers of electric vehicle charging services as public utilities, the CPUC has authority to regulate aspects of electric vehicle charging services. These aspects include rules relating to the deployment of electric vehicles; the terms under which a utility will provide services to the electric vehicle charging provider; retail electricity rates paid by the electric vehicle charging provider to a regulated utility; standards and protocols to ensure functionality and interoperability between utilities and electric vehicle charging providers; and various electricity procurement requirements that apply to electricity service providers generally, such as resource adequacy and renewable energy procurement standards. A second phase of the CPUC proceeding will examine the role of the regulated utility in electric vehicle charging programs, ways to manage the impact of such programs on the electric infrastructure, the cost to customers of such programs, and other issues.

Competition in the Natural Gas Industry

FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation, and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service whether or not the customer (often a local gas distribution company) buys the natural gas commodity from these companies. The Utility’s natural gas pipelines are located within the State of California and are exempt from the FERC’s rules and regulations applicable to interstate pipelines; the Utility’s pipeline operations are instead subject to the jurisdiction of the CPUC.

The Utility’s gas transmission and storage system has operated under the CPUC-approved “Gas Accord” market structure since 1998. This market structure largely mimics the regulatory framework required by the FERC for interstate gas pipelines. The CPUC divides the Utility’s natural gas customers into two categories: “core” customers who are primarily small commercial and residential customers, and “non-core” customers who are primarily industrial, large commercial, and electric generation customers. Under the Gas Accord structure, non-core customers have access to capacity rights for firm service, as well as interruptible (or “as-available”) services. All services are offered on a nondiscriminatory basis to any creditworthy customer. The Gas Accord market structure has resulted in a robust wholesale gas commodity market at the Utility’s “citygate,” which refers to the interconnection between the big “backbone” gas transmission system and the smaller downstream local transmission systems.

The Gas Accord separated the Utility’s natural gas transmission and storage rates from its distribution services and rates. The Gas Accord also changed the nature of the Utility’s transmission and storage services by creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for trading of firm capacity rights. Additionally, the Gas Accord eliminated balancing account protection for some services, increasing the Utility’s risk/reward potential. The Utility’s first Gas Accord, a settlement agreement reached among the Utility and many interested parties, was approved by the CPUC in 1997, took effect on March 1, 1998, and was renewed, with slight modifications, for various successive periods. On August 20, 2010, the Utility and other settling parties requested that the CPUC approve another settlement agreement known as the Gas Accord V to continue a majority of the Gas Accord’s terms and conditions for the Utility’s natural gas transportation and storage services beginning January 1, 2011 and continuing through 2014. (See “Regulatory Matters – 2011 Gas Transmission and Storage Rate Case” in the 2010 Annual Report.)

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The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services. The most important competitive factor affecting the Utility’s market share for transportation of natural gas to the southern California market is the total delivered cost of western Canadian natural gas relative to the total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in the Utility’s case, includes the cost of transportation of the natural gas from Canada to the California border and the amount that the Utility charges for transportation from the border to southern California. In general, when the total cost of western Canadian natural gas increases relative to other competing natural gas sources, the Utility’s market share of transportation services into southern California decreases. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.

Ratemaking Mechanisms

Overview

The Utility’s rates for electricity and natural gas utility services are based on its costs of providing service (“cost-of-service ratemaking”). Before setting rates, the CPUC and the FERC determine the annual amount of revenue (“revenue requirements”) that the Utility is authorized to collect from its customers. The CPUC determines the Utility’s revenue requirements associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. The FERC determines the Utility’s revenue requirements associated with its electricity transmission operations.

Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital costs of providing utility services as well as a return of, and a fair rate of return on, its investment in utility facilities (“rate base”). Revenue requirements are primarily determined based on the Utility’s forecast of future costs. These costs include the Utility’s costs of electricity and natural gas purchased for its customers, operating expenses, administrative and general expenses, depreciation, taxes, and public purpose programs.

Regulatory balancing accounts are used to adjust the Utility’s revenue requirements. Sales balancing accounts track differences between the Utility’s recorded revenues and its authorized revenue requirements, due primarily to sales fluctuations. In general, electricity sales are higher in the summer months and natural gas sales are higher in the winter months. Cost balancing accounts track differences between the Utility’s incurred costs and its authorized revenue requirements, most importantly for energy commodity costs and volumes that can be affected by seasonal demand, weather, and other factors. Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.

To develop retail rates, the revenue requirements are allocated among customer classes (mainly residential, commercial, industrial, and agricultural) and to various service components (mainly customer, demand, and energy). Specific rate components are designed to produce the required revenue. Rate changes become effective prospectively on or after the date of CPUC or FERC decisions. Most rate changes approved by the CPUC throughout the year are consolidated to take effect on the first day of the following year.

Through cost-of-service ratemaking, rates are developed to produce the revenue requirements, including the authorized return on rate base. The Utility may be unable to earn its authorized rate of return because the CPUC or the FERC excludes some of the Utility’s actual costs from the revenue requirements or because the Utility’s actual costs are higher than those reflected in the revenue requirements.

While the CPUC generally uses cost-of-service ratemaking to develop revenue requirements and rates, it selectively uses incentive ratemaking, which bases rates on the extent to which the utilities meet objective or fixed standards or goals, such as reliability standards or energy efficiency goals, instead of on the cost of providing service.

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Electricity and Natural Gas Distribution and Electricity Generation Operations

General Rate Cases

The General Rate Case (“GRC”) is the primary proceeding in which the CPUC determines the amount of revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s basic business and operational costs related to its electricity and natural gas distribution and electricity generation operations. The CPUC generally conducts a GRC every three years. The CPUC sets revenue requirement levels for a three-year rate period based on a forecast of costs for the first or “test” year. Typical interveners in the Utility’s GRC include the CPUC’s Division of Ratepayer Advocates (“DRA”) and The Utility Reform Network (“TURN”). In the Utility’s currently pending GRC, the CPUC will authorize the Utility’s revenue requirements for 2011 through 2013. On October 15, 2010, the Utility, together with the DRA, TURN, Aglet Consumer Alliance, and nearly all other intervening parties, filed a motion with the CPUC seeking approval of a settlement agreement to resolve almost all of the issues raised by the parties in the Utility’s 2011 GRC. For more information, see “Regulatory Matters – 2011 General Rate Case” in the 2010 Annual Report.

Attrition Rate Adjustments

The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC in order to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations. The proposed settlement agreement in the Utility’s 2011 GRC includes a provision for attrition rate increases in 2012 and 2013.

Cost of Capital Proceedings

The CPUC authorizes the Utility’s capital structure (i.e., the relative weightings of common equity, preferred equity, and debt) and the authorized rates of return on each component that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The current authorized capital structure consisting of 52% equity, 46% long-term debt, and 2% preferred stock will remain in effect through 2012 unless the automatic adjustment mechanism described below is triggered.

The CPUC has adopted a cost of capital adjustment mechanism which uses an interest rate index (the 12-month October through September average of the Moody’s Investors Service utility bond index) to trigger changes in the authorized cost of debt, preferred stock, and equity. In any year in which the 12-month October through September average for the index increases or decreases by more than 100 basis points (“deadband”) from the benchmark, the cost of equity will be adjusted by one-half of the difference between the 12-month average and the benchmark. In addition, if the mechanism is triggered, the costs of long-term debt and preferred stock will be adjusted to reflect the actual August month-end embedded costs in that year and forecasted interest rates for variable long-term debt and any new long-term debt and preferred stock forecasted to be issued in the coming year.

This mechanism did not trigger a change in the Utility’s authorized rates of return for 2011 which remain set at 6.05% for long-term debt, 5.68% for preferred stock, and 11.35% for common equity, resulting in an overall rate of return on rate base of 8.79%.

The Utility’s next full cost of capital application must be filed by April 20, 2012, so that any resulting changes would become effective on January 1, 2013. The Utility may apply for an adjustment to either the capital structure or the cost of capital sooner based on extraordinary circumstances.

Although the FERC has authority to set the Utility’s rate of return for its electricity transmission operations, the rate of return is often unspecified if the Utility’s transmission rates are determined through a negotiated rate settlement.

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Rate Recovery of Costs of New Electricity Generation Resources

Overview

Each California investor-owned electric utility is responsible for procuring electricity to meet customer demand, plus applicable reserve margins, not satisfied from that utility’s own generation facilities and existing electricity contracts (including DWR contracts allocated to the Utility under Assembly Bill 1X). To accomplish this, each utility must submit a long-term procurement plan covering a 10-year period to the CPUC for approval. Each long-term procurement plan must be designed to reduce GHG emissions and use the State of California’s preferred loading order to meet forecasted demand (i.e., increases in future demand will be offset through energy efficiency programs, demand response programs, renewable generation resources, distributed generation resources, and new conventional generation).

In December 2007, the CPUC approved the utilities’ long-term electricity procurement plans, covering 2007 through 2016, subject to certain required modifications. California legislation, Assembly Bill 57, allows the utilities to recover the costs incurred in compliance with their CPUC-approved procurement plans without further after-the-fact reasonableness review. Each utility may, if appropriate, conduct a competitive request for offers (“RFO”) within the parameters permitted in its approved plan to meet the utility’s projected need for electricity resources. Contracts that are entered into after the RFO process are submitted to the CPUC for approval, along with a request for the CPUC to authorize revenue requirements to recover the associated costs. The utilities conduct separate competitive solicitations to meet their renewable energy resource requirements. The utilities submit the renewable energy contracts after the conclusion of these solicitations to the CPUC for approval and authorization of the associated revenue requirements. For more information, see “Electric Utility Operations — Electricity Resources — Future Long-Term Generation Resources” below.

The Utility recovers its electricity procurement costs and the fuel costs for the Utility’s own generation facilities (but excluding the costs of electricity allocated to the Utility’s customers under DWR contracts) through the Energy Resource Recovery Account (“ERRA”), a balancing account authorized by the CPUC in accordance with Assembly Bill 57. The ERRA tracks the difference between (1) billed/unbilled ERRA revenues and (2) electric procurement costs incurred under the Utility’s authorized procurement plans. To determine rates used to collect ERRA revenues, each year the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements and generation fuel expense and approves a forecasted revenue requirement. The CPUC also performs an annual compliance review of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are prudent and in compliance with its CPUC-approved procurement plans.

Although California legislation requiring the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utility’s prior year electricity procurement revenues (excluding amounts collected for the DWR contracts) expired on January 1, 2006, the CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including power purchase costs.

The CPUC has not yet issued a decision to complete the Utility’s 2009 ERRA compliance review proceeding.

Costs Incurred Under New Power Purchase Agreements

The CPUC has approved various power purchase agreements that the Utility has entered into with third parties in accordance with the Utility’s CPUC-approved long-term procurement plan and to meet renewable energy and resource adequacy requirements. The CPUC also authorized the Utility to recover fixed and variable costs associated with these contracts through the ERRA.

For new non-renewable generation purchased from third parties under power purchase agreements, the Utility may elect to recover any above-market costs through either (1) the imposition of a non-bypassable charge on bundled and departing customers only or (2) the allocation of the “net capacity costs” (i.e., contract price less energy revenues) to all “benefiting customers” in the Utility’s service territory, including existing direct access customers and community choice aggregation customers. (For information about the status of direct access and community choice aggregation, see the section above entitled “Competition in the Electricity Industry.”)

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The non-bypassable charge can be imposed from the date of signing a power purchase agreement and can last for 10 years from the date the new generation unit comes on line or for the term of the contract, whichever is less. Utilities are allowed to justify a cost recovery period longer than 10 years on a case-by-case basis. If a utility elects to use the net capacity cost allocation method, the net capacity costs are allocated for the term of the contract or 10 years, whichever is shorter, starting on the date the new generation unit comes on line. Under this allocation mechanism, the energy rights to the contract are auctioned off to maximize the energy revenues and minimize the net capacity costs subject to allocation. If no bids are accepted for the energy rights, the Utility would retain the rights to the energy and would value it at market prices for the purposes of determining the net capacity costs to be allocated until the next periodic auction.

California Senate Bill 695, enacted on October 11, 2009, also includes a mechanism for recovery of above-market costs from direct access and community choice aggregation customers. The CPUC has not yet implemented this portion of Senate Bill 695.

Costs of Utility-Owned Generation Resource Projects

The CPUC-authorized revenue requirements for capital costs and non-fuel operating and maintenance costs for operating Utility-owned generation facilities are addressed in the Utility’s GRC. The CPUC-authorized revenue requirements to recover the initial capital costs for utility-owned generation projects are recovered through a balancing account, the Utility Generation Balancing Account (“UGBA”), which tracks the difference between the CPUC-approved forecast of initial capital costs, adjusted from time to time as permitted by the CPUC, and actual costs. The initial revenue requirement for Utility-owned projects generally would begin to accrue in the UGBA as of the new facility’s commercial operation date or the date a completed facility is transferred to the Utility, and would be included in rates on January 1 of the following year. For more information, see “Capital Expenditures” in the 2010 Annual Report.

DWR Electricity and DWR Revenue Requirements

During the 2000-2001 California energy crisis the DWR entered into long-term contracts to purchase electricity from third parties. The electricity provided under these contracts has been allocated to the electric customers of the three California investor-owned electric utilities. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from these customers through a rate component called the DWR “power charge.” The rates that these customers pay also include a “bond charge” to pay a share of the DWR’s revenue requirements to recover costs associated with the DWR’s $11.3 billion bond offering completed in November 2002. The proceeds of this bond offering were used to repay the State of California and lenders to the DWR for electricity purchases made before the implementation of the DWR’s revenue requirement and to provide the DWR with funds to make its electricity purchases. The Utility acts as a billing and collection agent for the DWR for these amounts; however, amounts collected for the DWR and any adjustments are not included in the Utility’s revenues.

Electricity Transmission

The Utility’s electricity transmission revenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main sources of transmission revenues (1) charges under the Utility’s transmission owner tariff and (2) charges under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations in March 1998. These wholesale customers are referred to as existing transmission contract customers and are charged individualized rates based on the terms of their contracts. Other customers pay transmission rates that are established by the FERC in the Utility’s transmission owner tariff rate cases. These FERC-approved rates are included by the CPUC in the Utility’s retail electric rates, consistent with the federal filed rate doctrine, and are collected from retail electric customers receiving bundled service.

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Transmission Owner Rate Cases

The primary FERC ratemaking proceeding to determine the amount of revenue requirements that the Utility is authorized to recover for its electric transmission costs and to earn its return on equity is the transmission owner rate case (“TO rate case”). The Utility generally files a TO rate case every year. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process. For more information about the Utility’s TO rate cases, see “Regulatory Matters — Electric Transmission Owner Rate Cases” in the 2010 Annual Report.

The Utility’s transmission owner tariff includes two rate components. The primary component consists of base transmission rates intended to recover the Utility’s operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense, and return on equity. The Utility derives the majority of the Utility’s transmission revenue from base transmission rates.

The other component consists of rates intended to reflect credits and charges from the CAISO. The CAISO credits the Utility for transmission revenues received by the CAISO for providing wholesale wheeling service (i.e., the transfer of electricity that is being sold in the wholesale market) to third parties using the Utility’s transmission facilities. These revenues are adjusted by the shortfall or surplus resulting from any cost differences between the amount that the Utility is entitled to receive from existing transmission contract customers under specific contracts and the amount that the Utility is entitled to receive or be charged for scheduling services under the CAISO’s rules and protocols.

The CAISO also charges the Utility for reliability service costs and imposes a transmission access charge on the Utility for the use of the CAISO-controlled electric transmission grid in serving its customers. This rate is based on the revenue requirements associated with facilities operated at 200 kV and above of all transmission-owning entities that become participating transmission owners under the CAISO tariff. The transmission access charge methodology results in a cost shift to transmission owners, whose costs for existing transmission facilities at 200 kV and above are higher than that embedded in the uniform transmission access charge rate, from transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The cost shift amounts are recovered from the Utility’s retail customers as part of retail transmission rates.

Natural Gas

The Gas Accord

The Utility’s authorized natural gas transmission and storage rates and associated revenue requirements from January 1, 2008 through December 31, 2010 were set in accordance with the CPUC-approved settlement agreement known as the Gas Accord IV. On August 20, 2010, the Utility and other settling parties requested that the CPUC approve another settlement agreement known as the Gas Accord V to continue a majority of the Gas Accord IV’s terms and conditions for the Utility’s natural gas transportation and storage services beginning January 1, 2011 and continuing through 2014. (See “Regulatory Matters- 2011 Gas Transmission and Storage Rate Case” in the 2010 Annual Report.) A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, would continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utility’s ability to recover the 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. This volumetric cost recovery risk associated with each function (backbone transmission, local transmission, and storage) is summarized below:

Backbone Transmission. The backbone transmission revenue requirement is recovered through a combination of firm two-part rates (consisting of fixed monthly reservation charges and volumetric usage charges) and as-available one-part rates (consisting only of volumetric usage charges). The mix of firm and as-available backbone services provided by the Utility continually changes. As a result, the Utility’s recovery of its backbone transmission costs is subject to volumetric and price risk to the extent that backbone capacity is sold on an as-available basis. Core procurement entities (including core customers served by the Utility) are the primary long-term subscribers to backbone capacity. Core customers are allocated approximately 36% of the total backbone capacity on the Utility’s system. Core customers pay approximately 72% of the costs of the backbone capacity that is allocated to them through fixed reservation charges.

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Local Transmission. The local transmission revenue requirement is allocated approximately 71% to core customers and 29% to non-core customers. The Utility recovers the portion allocated to core customers through a balancing account, but the Utility’s recovery of the portion allocated to non-core customers is subject to volumetric and price risk.

Storage. The storage revenue requirement is allocated approximately 71% to core customers, 12% to non-core storage service, and 17% to pipeline load balancing service. The Utility recovers the portion allocated to core customers through a balancing account, but the Utility’s recovery of the portion allocated to non-core customers is subject to volumetric and price risk. The revenue requirement for pipeline load balancing service is recovered in backbone transmission rates and is subject to the same cost recovery risks described above for backbone transmission.

Biennial Cost Allocation Proceeding

Certain of the Utility’s natural gas distribution costs and balancing account balances are allocated to customers in the CPUC’s Biennial Cost Allocation Proceeding. This proceeding normally occurs every two years and is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any under-collection, or refund to customers any over-collection, in the balancing accounts. Balancing accounts for gas distribution and other authorized expenses accumulate differences between authorized amounts and actual revenues.

Natural Gas Procurement

The Utility sets the natural gas procurement rate for core customers monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates.

The Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates. The Utility is protected against after-the-fact reasonableness reviews of these gas procurement costs under the Core Procurement Incentive Mechanism (“CPIM”). Under the CPIM, the Utility’s purchase costs for a fixed 12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers’ rates, and the Utility’s customers receive in their rates 80% of any savings resulting from the Utility’s cost of natural gas that is less than 99% of the benchmark. The remaining amount of savings are retained by the Utility as incentive revenues, subject to a cap equal to the lower of 1.5% of total natural gas commodity costs or $25 million. While this incentive mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income.

In January 2010, the CPUC approved a joint settlement agreement among the Utility, the CPUC’s Division of Ratepayer Advocates, and The Utility Reform Network to incorporate a portion of hedging costs for core customers into the Utility’s CPIM beginning November 1, 2010. The settlement agreement has an initial term of seven years, through October 2017, which can be extended by agreement of the parties. As a result, the settlement agreement permits the Utility to develop and implement a sustained core hedging program. (For more information, see Note 10: Derivatives and Hedging Activities, of the Notes to the Consolidated Financial Statements in the 2010 Annual Report).

Interstate and Canadian Natural Gas Transportation

The Utility’s interstate and Canadian natural gas transportation agreements with third-party service providers are governed by tariffs that detail rates, rules, and terms of service for the provision of natural gas

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transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process, and the applicable Canadian tariffs are approved by the Alberta Utilities Commission and the National Energy Board. The Utility’s agreements with interstate and Canadian natural gas transportation service providers are administered as part of the Utility’s core natural gas procurement business. Their purpose is to transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. For more information, see the discussion below under “Natural Gas Utility Operations — Interstate and Canadian Natural Gas Transportation Services Agreements.”

Electric Utility Operations

Electricity Resources

The Utility is required to maintain physical generating capacity adequate to meet its customers’ demand for electricity (“load”), including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service. The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. The following table shows the percentage of the Utility’s total actual deliveries of electricity in 2010 represented by each major electricity resource:

Total 2010 Actual Electricity Delivered: 77,772 GWh:

Owned generation:
Nuclear	23.72	%
Small Hydroelectric	1.49	%
Large Hydroelectric	12.68	%
Fossil fuel-fired	4.65	%
Solar	0.01	%
Other (RFO, Diesel)	0.01	%
Total			42.56	%
DWR
Natural Gas			5.85	%
Qualifying Facilities
Renewable	4.99	%
Non-Renewable	13.51	%
Total			18.50	%
Irrigation Districts
Small Hydroelectric	0.51	%
Large Hydroelectric	4.01	%
Total			4.52	%
Bilateral
Renewable	8.87	%
Large Hydroelectric	0.26	%
Non-Renewable	1.07	%
Total			10.20	%
Open Market
Unspecified			18.37	%

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Owned Generation Facilities

At December 31, 2010, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:

Generation Type	County Location	Number of          Units		Net  Operating Capacity (MW)
Nuclear:
Diablo Canyon	San Luis Obispo		2		2,240
Hydroelectric:
Conventional	16 counties in northern and central California		107		2,684
Helms pumped storage	Fresno		3		1,212
Hydroelectric subtotal:			110		3,896
Fossil fuel:
Colusa Generating Station (1)	Colusa		1		530
Gateway Generating Station (2)	Contra Costa		1		530
Humboldt Bay Generating Station (3)(4)	Humboldt		9		146
Fossil fuel subtotal:			11		1,206
Total			123		7,342

(1) The Colusa Generating Station became operational in December 2010 with 530 MW of base capacity and 127 MW of enhanced capability.

(2) The Gateway Generating Station consists of 530 MW of base capacity and 50 MW of enhanced capability.

(3) Humboldt Bay Generating Station became operational in September 2010.

(4) The Humboldt Bay Power Plant fossil facilities, two operating fossil fuel-fired plants and two mobile turbines, were retired at the end of September 2010.

Diablo Canyon Power Plant. The Utility’s Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2, with a total-plant net generation capacity of approximately 2,240 MW of electricity. For the twelve months period ended December 31, 2010, the Utility’s Diablo Canyon power plant achieved an average overall capacity factor of approximately 95%. The NRC operating license for Unit 1 expires in November 2024, and the NRC operating license for Unit 2 expires in August 2025. In November 2009, the Utility filed an application at the NRC requesting that each of these licenses be renewed for 20 years. The license renewal process is expected to take several years as the NRC holds public hearings and conducts safety and environmental analyses and site audits. (See the discussion under the heading “Risk Factors” that appears in the MD&A section of the 2010 Annual Report.) Under the terms of the NRC operating licenses, there must be sufficient storage capacity for the radioactive spent fuel produced by the Diablo Canyon plant. For a discussion of the Utility’s spent fuel storage project, see “Environmental Matters — Nuclear Fuel Disposal” below.

The ability of the Utility to produce nuclear generation depends on the availability of nuclear fuel. The Utility has entered into various purchase agreements for nuclear fuel that are intended to ensure long-term fuel supply. For more information about these agreements, see Note 15: Commitments and Contingencies — Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.

The following table outlines the Diablo Canyon power plant’s refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 20 months. The average length of a refueling outage over the last five years has been approximately 46 days. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

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	2011	2012	2013	2014	2015
Unit 1
Refueling	-	April	-	February	-
Duration (days)	-	45	-	35	-
Startup	-	June	-	March	-
Unit 2
Refueling	May	-	February	September	May
Duration (days)	40	-	45	35	30
Startup	June	-	March	October	May

Hydroelectric Generation Facilities. The Utility’s hydroelectric system consists of 110 generating units at 69 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. Most of the Utility’s hydroelectric generation units are classified as “large” hydro facilities, as their unit capacity exceeds 30 MW. The system includes 99 reservoirs, 56 diversions, 170 dams, 172 miles of canals, 43 miles of flumes, 130 miles of tunnels, 54 miles of pipe (penstocks, siphons and low head pipes), and 5 miles of natural waterways. The system also includes water rights as specified in 89 permits or licenses and 159 statements of water diversion and use.

All of the Utility’s powerhouses are licensed by the FERC (except for three small powerhouses not subject to FERC licensing requirements), with license terms between 30 and 50 years. In the last three years, the FERC renewed two hydroelectric licenses associated with a total of 110 MW of hydroelectric power. The Utility is in the process of renewing licenses for projects associated with approximately 1,077 MW of hydroelectric power. Although the original licenses associated with 520 MW of the 1,077 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process.  Licenses associated with approximately 3,367 MW of hydroelectric power will expire between 2011 and 2047.

DWR Power Purchases

During 2010, electricity from the DWR contracts allocated to the Utility provided approximately 6% of the electricity delivered to the Utility’s customers. The DWR purchased the electricity under contracts with various generators. The Utility, as an agent, is responsible for administration and dispatch of these DWR contracts and acts as a billing and collection agent. The DWR remains legally and financially responsible for its contracts. The Utility expects that the amount of power supplied under the DWR’s contracts will diminish in the future as these contracts expire or are novated to the Utility.

Third-Party Power Purchase Agreements

Qualifying Facility Power Purchase Agreements. As described above under “The Utility’s Regulatory Environment-Federal Energy Regulation,” the Utility currently is required to purchase energy and capacity from independent power producers that are QFs. As of December 31, 2010, the Utility had power purchase agreements with 226 QFs for approximately 3,700 MW that are in operation. Agreements for approximately 3,400 MW expire at various dates between 2011 and 2028. QF power purchase agreements for approximately 300 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option. The Utility also has power purchase agreements with approximately 75 inoperative QFs. The total of approximately 3,700 MW consists of 2,500 MW from cogeneration projects, and 1,200 MW from renewable generation resources, as discussed below. QF power purchases accounted for 18.5% of the Utility’s 2010 electricity deliveries. No single QF accounted for more than 5% of the Utility’s 2010 electricity deliveries.

In December 2010, the CPUC approved a settlement agreement among the California investor-owned utilities, ratepayer groups, and representatives of the facilities that use combined heat and power (“CHP”), including CHP facilities that also qualify as QFs. The settlement establishes a new CHP/QF program that sets CHP procurement targets and GHG reduction targets (consistent with AB 32), provides for a transition of existing QF energy pricing to market-based pricing by 2015, and implements new standard power purchase agreements. In accordance with the settlement agreement, the utilities will file a joint application with the FERC requesting the

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FERC to terminate the utilities’ obligations under PURPA to purchase power from all QFs sized 20 MW and above which includes the settling CHP/QFs. The settlement agreement will become effective when the CPUC decision becomes final and non-appealable, and when a FERC decision granting the utilities’ PURPA termination application becomes final and non-appealable. The FERC is expected to issue a decision on the utilities’ application in the second quarter of 2011.

Irrigation Districts and Water Agencies. The Utility also has entered into contracts with various irrigation districts and water agencies to purchase hydroelectric power. These agreements are based on debt service requirements (regardless of the amount of power supplied), and include variable payments to the counterparty for operation and maintenance costs. These contracts will expire on various dates between 2011 and 2031. In 2010, they accounted for 4.52% of the Utility’s electricity deliveries.

Other Power Purchase Agreements. The Utility has entered into power purchase agreements, including agreements to purchase renewable energy that were entered into following annual solicitations and separate bilateral negotiations. In addition, in accordance with the Utility’s CPUC-approved long-term procurement plan, the Utility has entered into power purchase agreements for conventional generation resources. During 2010, the Utility’s purchases under these agreements accounted for 10.20% of the Utility’s deliveries. When market prices and forecasted load conditions are favorable, the Utility also has the ability to procure electricity through the spot bilateral and CAISO markets. Electricity purchased in these markets accounted for 18.38% of the Utility’s deliveries in 2010.

For more information regarding the Utility’s power purchase contracts, see Note 15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.

Renewable Generation Resources

Current 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, small hydroelectric, wind, solar, and geothermal energy) each year, so that the amount of electricity delivered from 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. Whether a retail seller who relies on flexible compliance rules has met the RPS target for a particular year may not be known until the end of the associated three-year roll-forward period. The CPUC has indicated that it currently intends to limit its discretion to levy penalties for an unexcused failure to meet an applicable RPS target to a maximum of $25 million per year per retail seller.

For the year ended December 31, 2010, the Utility’s RPS-eligible renewable resource deliveries equaled 15.9% of its total retail electricity sales. Most renewable energy deliveries resulted from third party contracts, mainly QF agreements and bilateral contracts. Additional renewable resources included the Utility’s small hydro and solar facilities and certain irrigation district contracts (small hydro facilities). (Under California law only hydroelectric generation resources with a capacity of 30 MW or less can qualify as a renewable resource for purposes of meeting the RPS mandate. Most of the Utility’s hydroelectric generating units have a capacity in excess of 30 MW and do not qualify as RPS-eligible resources.)

Total 2010 renewable deliveries are stated in the table below.

Type	GWh		% of Bundled Load
Biopower		3,288		4.9	%
Geothermal		3,767		4.2	%
Wind		2,972		3.8	%
Small Hydroelectric		2,243		2.9	%
Solar		63		0.1	%
Total		12,333		15.9	%

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For more information regarding the Utility’s renewable energy contracts, see Note 15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.

In April 2010, the CPUC approved the Utility’s proposed five-year program for the development of up to 250 MW of solar photovoltaic (“PV”) facilities and to enter into power purchase agreements for an additional 250 MW of PV facilities to be developed by third parties.

In addition, under its authority to implement AB 32, the CARB has adopted regulations that require virtually all load-serving entities, including the Utility, to increase their deliveries of renewable energy to meet specific annual targets. For 2012, 2013, and 2014, the amount of electricity delivered from renewable energy resources must equal at least 20% of total energy deliveries, increasing to 24% in 2015, 2016, and 2017, 28% in 2018 and 2019, and 33% in 2020 and beyond. For more information about these renewable energy requirements, see “Environmental Matters-Renewable Energy Resources” in the 2010 Annual Report.

Finally, legislation has been introduced in the California state legislature that proposes to increase the current RPS from 20% to 33% by 2020. Under the proposed bill, Senate Bill 23, the amount of electricity delivered from renewable energy resources must equal at least 25% of total energy deliveries by December 31, 2016 and 33% by December 31, 2020. If enacted, the bill would become effective on January 1, 2012. It is unclear how this proposed legislation, if adopted, would affect the CARB’s renewable energy delivery requirement.

Future Long-Term Generation Resources

The Utility plans to meet future electricity demand by focusing first on reducing consumption through energy efficiency and demand response programs, then by securing environmentally preferred energy resources, such as renewable generation and distributed generation (including solar power), and finally by relying on clean and efficient fossil-fueled generation resources. The CPUC has authorized the Utility to obtain new long-term generation resources to meet approximately 1,500 MW of forecast demand by 2016 through power purchase agreements or the development of new Utility-owned generation facilities.

The CPUC allows the California investor-owned utilities to acquire ownership of new conventional generation resources through purchase and sale agreements (“PSAs”) (a PSA is a “turnkey” arrangement in which a new generating facility is constructed by a third party and then sold to the Utility upon satisfaction of certain contractual requirements). The utilities are prohibited from submitting offers for utility-build generation in their respective RFOs until questions can be resolved about how to compare offers for utility-owned generation with offers from independent power producers. The utilities are permitted to propose utility-owned generation projects through a separate application outside of the RFO process in the following circumstances: (1) to mitigate market power demonstrated by the utility to be held by others, (2) to support a use of preferred resources, such as renewable energy sources, (3) to take advantage of a unique and fleeting opportunity (such as a bankruptcy settlement), and (4) to meet unique reliability needs.

The CPUC has recently approved the Utility’s proposal to acquire the 586-MW Oakley Generation Station to be developed and constructed by a third party; however several applications for rehearing of this decision have been filed. For more information, see “Capital Expenditures” in the 2010 Annual Report.

Electricity Transmission

At December 31, 2010, the Utility owned approximately 18,600 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of approximately 57,953 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through approximately 141,346 circuit miles of distribution lines and substations with a capacity of 28,244 MVA. In 2010, the Utility delivered 77,772 GWh to its customers, and approximately 6,000 GWh to direct access customers. The Utility is interconnected with electric power systems in the WECC, which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.

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During 1998, in connection with electric industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the CAISO. The Utility entered into a Transmission Control Agreement with the CAISO and other participating transmission owners (including Southern California Edison Company, San Diego Gas & Electric Company, and several California municipal utilities) under which the transmission owners have assigned operational control of their electric transmission systems to the CAISO. The Utility is required to give the CAISO two years notice and receive approval from the FERC if it wishes to withdraw from the Transmission Control Agreement and take back operational control of its transmission facilities.

The CAISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The CAISO also is responsible for ensuring that the reliability of the transmission system is maintained. The Utility acts as a scheduling coordinator to schedule electricity deliveries to the transmission grid. The Utility also acts as a scheduling coordinator to deliver electricity produced by several governmental entities to the transmission grid under contracts the Utility entered into with these entities before the CAISO commenced operation in 1998. In addition, under the mandatory reliability standards implemented following the EPAct, all users, owners, and operators of the transmission system, including the Utility, are also responsible for maintaining reliability through compliance with the reliability standards. See the discussion of reliability standards above under “The Utility’s Regulatory Environment — Federal Energy Regulation.”

The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, to maintain system reliability, and to reduce reliance on generation provided under reliability must run (“RMR”) agreements with the CAISO. (RMR agreements require various power plant owners, including the Utility, to keep designated units in certain power plants, known as RMR units, available to generate electricity upon the CAISO’s demand when the generation from those RMR units is needed for local transmission system reliability.)

Electricity Distribution Operations

The Utility’s electricity distribution network extends through 47 of California’s 58 counties, comprising most of northern and central California. The Utility’s network consists of approximately 141,000 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). There are 93 transmission substations and 48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. The Utility’s network includes 600 distribution substations and 118 low-voltage distribution substations. The 53 combined transmission and distribution substations have both transmission and distribution transformers.

The Utility’s distribution network interconnects to the Utility’s electricity transmission system at approximately 1,122 points. This interconnection between the Utility’s distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’s customers. The distribution substations serve as the central hubs of the Utility’s electricity distribution network and consist of transformers, voltage regulation equipment, protective devices, and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or other facilities to entities, such as municipal and other utilities, that then resell the electricity.

Much of the Utility’s electric transmission and distribution infrastructure was placed into service in the 1940’s through the 1960’s as California’s population and economy grew. The Utility makes capital investments in its electric transmission and distribution infrastructure to extend the life of or replace existing infrastructure; to maintain and improve system reliability, safety, and customer service; and to add new infrastructure to meet customer demand growth.

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The CPUC has authorized the Utility to install approximately 10 million advanced electric and gas meters using SmartMeter™ technology throughout the Utility’s service territory by the end of 2012. As of December 31, 2010, the Utility has installed approximately 7.5 million advanced electric and gas meters through its service territory. 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.

Following customer complaints that the new metering system led to overcharges, the CPUC began an investigation, several municipalities took various steps to delay or suspend the installation of the new meters, and a class action lawsuit was filed against the Utility. In addition, customers and other private groups have raised safety and health concerns about the radio frequency technology (“RF”) used in the new system. For information about these matters, see “Regulatory Matters-Deployment of SmartMeter^TM Technology” in the 2010 Annual Report. The Utility expects to complete the installation of the new meters by the end of 2012.

2010 Electricity Deliveries

The following table shows the percentage of the Utility’s total 2010 electricity deliveries represented by each of its major customer classes.

    Total 2010 Electricity Delivered: 83,908 GWh

Residential Customers	37	%
Commercial Customers	39	%
Industrial Customers	17	%
Agricultural and Other Customers	7	%

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Electricity Distribution Operating Statistics

The following table shows certain of the Utility’s operating statistics from 2006 to 2010 for electricity sold or delivered, including the classification of sales and revenues by type of service.

	2010			2009			2008			2007			2006
Customers (average for the year):
Residential		4,509,620			4,492,359			4,488,884			4,464,483			4,417,638
Commercial		529,318			528,786			527,045			521,732			515,297
Industrial		1,254			1,285			1,265			1,261			1,212
Agricultural		83,787			83,581			81,757			80,366			79,006
Public street and highway lighting		31,743			31,227			30,474			29,643			28,799
Other electric utilities		2			2			2			2			4
Total		5,155,724			5,137,240			5,129,427			5,097,487			5,041,956
Deliveries (in GWh): (1)
Residential		30,744			31,234			31,454			30,796			31,014
Commercial		32,863			32,958			34,053			33,986			33,492
Industrial		14,415			14,806			16,148			15,159			15,166
Agricultural		5,071			5,804			5,594			5,402			3,839
Public street and highway lighting		815			826			877			833			785
Other electric utilities		-			1			1			3			14
Subtotal		83,908			85,629			88,127			86,179			84,310
California Department of Water Resources (DWR)		(4,274	)		(13,244	)		(13,344	)		(21,193	)		(19,585	)
Total non-DWR electricity		79,634			72,385			74,783			64,986			64,725
Revenues (in millions):
Residential		$  4,795			$  4,759			$  4,656			$  4,580			$  4,491
Commercial		4,823			4,538			4,413			4,484			4,414
Industrial		1,424			1,392			1,400			1,252			1,293
Agricultural		736			770			727			664			483
Public street and highway lighting		79			74			75			78			72
Other electric utilities		60			66			126			85			59
Subtotal		11,917			11,599			11,397			11,143			10,812
DWR		(1,383	)		(1,987	)		(1,325	)		(2,229	)		(2,119	)
Miscellaneous		145			221			336			215			261
Regulatory balancing accounts		(35	)		424			330			352			(202	)
Total electricity operating revenues		$  10,644			$  10,257			$  10,738			$  9,481			$  8,752
Other Data:
Average annual residential usage (kWh)		6,843			6,953			7,007			6,898			7,020
Average billed revenues (cents per kWh):
Residential		$  15.60			$  15.24			$  14.80			$  14.87			$  14.48
Commercial		14.68			13.77			12.96			13.19			13.18
Industrial		9.88			9.40			8.67			8.26			8.53
Agricultural		14.51			13.27			13.00			12.29			12.58
Net plant investment per customer		$  4,728			$  4,336			$  3,994			$  3,418			$  3,148

⁽¹⁾ These amounts include electricity provided to direct access customers who procure their own supplies of electricity.

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Natural Gas Utility Operations

The Utility owns and operates an integrated natural gas transportation, storage, and distribution system in California that extends throughout all or a part of 39 of California’s 58 counties and includes most of northern and central California. In 2010, the Utility served approximately 4.3 million natural gas distribution customers.

The CPUC divides the Utility’s natural gas customers into two categories: core and non-core customers. This classification is based largely on a customer’s annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The non-core customer class is comprised of industrial, larger commercial, and electric generation natural gas customers. In 2010, core customers represented more than 99% of the Utility’s total natural gas customers and 39% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total natural gas customers and 61% of its total natural gas deliveries.

The Utility provides natural gas transportation services to all core and non-core customers connected to the Utility’s system in its service territory. Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or alternate energy service providers. When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service. Currently, over 97% of core customers, representing over 96% of the annual core market demand, receive bundled natural gas service from the Utility.

The Utility does not provide procurement service to non-core customers. However, some non-core customers are permitted to elect core service and receive Utility procurement service subject to eligibility requirements. Electricity generators, QF cogenerators, enhanced oil recovery customers, refiners, and other large non-core customers may not elect core service, and smaller non-core customers must contract for a minimum five-year term if they elect core service. These restrictions were put in place because large increases in demand for the Utility’s procurement service caused by significant transfers of non-core customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.

The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers. Access to the Utility’s backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers.

The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility’s results of operations over the long term are not affected by weather variations, conservation, or changes in their consumption levels. The Utility’s results of operations can, however, be affected by non-core consumption levels because there are fewer regulatory balancing accounts related to non-core customers. Approximately 97% of the Utility’s natural gas distribution base revenues are recovered from core customers and 3% are recovered from non-core customers.

Natural Gas System

As of December 31, 2010, the Utility’s natural gas system consisted of approximately 43,000 miles of distribution pipelines, approximately 6,000 miles of backbone and local transmission pipelines, and three storage facilities. The Utility’s backbone transmission system, composed primarily of Lines 300, 400, and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution systems. The Utility’s Line 300, which interconnects with the U.S. Southwest and Rocky Mountain pipeline systems owned by third parties (Transwestern Pipeline Company, El Paso Natural Gas Company, Questar Southern Trails Pipeline Company, and Kern River Pipeline Company), has a receipt capacity of approximately 1.07 Bcf per day. The Utility’s Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.02 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States. The Utility also is supplied by natural gas fields in California.

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Much of the Utility’s natural gas transmission and distribution infrastructure was placed into service in the 1940’s through the 1960’s as California’s population and economy grew. The Utility makes capital investments in its natural gas transmission and distribution infrastructure to extend the life of or replace existing infrastructure; to maintain and improve system reliability, safety, and customer service; and to add new infrastructure to meet customer demand growth.

The Utility owns and operates three underground natural gas storage fields connected to the Utility’s transmission and storage system. These storage fields have a combined firm capacity of approximately 50 Bcf. In addition, two independent storage operators are interconnected to the Utility’s northern California transportation system.

The Utility, along with Gill Ranch Storage, LLC, a subsidiary of Northwest Natural Gas Company, has placed into operation an underground natural gas storage facility near Fresno, California. The construction of the initial phase, consisting of approximately 20 Bcf of total capacity, was completed in 2010. The Utility has a 25% interest in the initial phase of the proposed storage facility.

2010 Natural Gas Deliveries

The total volume of natural gas throughput during 2010 was approximately 7,404 MMDth. The following table shows the percentage of the Utility’s total 2010 natural gas deliveries represented by each of the Utility’s major customer classes.

Total 2010 Natural Gas Deliveries: 842 Bcf

Residential Customers	28	%
Transport-only Customers (non-core)	60	%
Commercial Customers	12	%

The California Gas Report is prepared by the California electric and natural gas utilities to present an outlook for natural gas requirements and supplies for California over a long-term planning horizon. It is prepared in even-numbered years followed by a supplemental report in odd-numbered years. The 2010 California Gas Report forecasts average annual growth in the Utility’s natural gas deliveries (for core customers and non-core transportation) of approximately 0.3% for the years 2010 through 2030. The natural gas requirements forecast is subject to many uncertainties, and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, price, and the number and location of electricity generation facilities.

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Natural Gas Operating Statistics

The following table shows the Utility’s operating statistics from 2006 through 2010 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service.

	2010		2009		2008		2007		2006
Customers (average for the year):
Residential		4,070,420		4,046,364		4,043,616		4,030,499		3,989,331
Commercial		224,400		223,709		224,617		223,330		220,024
Industrial		915		928		926		958		988
Other gas utilities		6		6		6		6		6
Total		4,295,741		4,271,007		4,269,165		4,254,793		4,210,349
Gas supply (MMcf):
Purchased from suppliers in:
Canada		206,800		190,485		189,608		199,870		202,274
California (1)		(32,910)		(41,714)		(53,126)		(23,065)		(13,401)
Other states		96,338		115,543		123,833		101,271		103,658
Total purchased		270,228		264,314		260,315		278,076		292,531
Net (to storage) from storage		(314)		876		560		(1,120)		4,359
Total		269,914		265,190		260,875		276,956		296,890
Utility use, losses, etc. (2)		(20,798)		(12,423)		1,758		(12,760)		(27,610)
Net gas for sales		249,116		252,767		262,633		264,196		269,280
Bundled gas sales (MMcf):
Residential		195,195		195,217		198,699		196,903		196,092
Commercial		53,921		57,550		63,934		67,293		73,178
Industrial		—		—		—		—		10
Other gas utilities		—		—		—		—		—
Total		249,116		252,767		262,633		264,196		269,280
Transportation only (MMcf):		564,516		568,715		569,535		605,259		559,270
Revenues (in millions):
Bundled gas sales:
Residential		$  1,991		$  1,953		$  2,574		$  2,378		$  2,452
Commercial		474		496		792		766		859
Industrial		—		—		—		—		—
Other gas utilities		—		—		—		—		—
Miscellaneous		49		55		(30)		87		121
Regulatory balancing accounts		305		289		221		186		40
Bundled gas revenues		2,819		2,793		3,557		3,417		3,472
Transportation service only revenue		377		349		333		340		315
Operating revenues		$  3,196		$  3,142		$  3,890		$  3,757		$  3,787
Selected Statistics:
Average annual residential usage (Mcf)		48		48		49		49		49
Average billed bundled gas sales revenues per Mcf:
Residential		$  10.20		$  10.00		$  12.95		$  12.07		$  12.50
Commercial		8.79		8.62		12.38		11.38		11.73
Industrial		—		—		—		—		1.03
Average billed transportation only revenue per Mcf		0.67		0.61		0.59		0.56		0.56
Net plant investment per customer		$  1,637		$  1,557		$  1,344		$  1,375		$  1,304

⁽¹⁾ In the years presented, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.

⁽²⁾ Includes fuel for the Utility’s fossil fuel-fired generation plants.

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Natural Gas Supplies

The Utility purchases natural gas to serve the Utility’s core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas purchase contracts have fluctuated generally based on market conditions. During 2010, the Utility purchased approximately 270,228 MMcf of natural gas (net of the sale of excess supply of gas). Substantially all this natural gas was purchased under contracts with a term of one year or less. The Utility’s largest individual supplier represented approximately 9% of the total natural gas volume the Utility purchased during 2010.

The following table shows the total volume and the average price of natural gas in dollars per MMcf of the Utility’s natural gas purchases by region during each of the last five years. The average prices for Canadian and U.S. Southwest gas shown below include the commodity natural gas prices, pipeline demand or reservation charges, transportation charges, and other pipeline assessments. The volumes purchased are shown net of sales of excess supplies of gas. In the years presented below, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.

	2010					2009					2008					2007					2006
	MMcf			Avg. Price		MMcf			Avg. Price		MMcf			Avg. Price		MMcf			Avg. Price		MMcf			Avg. Price
Canada		206,800		$	4.03		190,485		$	3.74		189,608		$	8.29		199,870		$	6.63		202,274		$	6.27
California (1)		(32,910	)	$	4.63		(41,714	)	$	4.16		(53,126	)	$	9.24		(23,065	)	$	6.77		(13,401	)	$	7.04
Other states (substantially all U.S. southwest)		96,338		$	4.34		115,543		$	3.50		123,833		$	7.05		101,271		$	6.30		103,658		$	6.51
Total/weighted average		270,228		$	4.07		264,314		$	3.57		260,315		$	7.51		278,076		$	6.50		292,531		$	6.32

⁽¹⁾ California purchases include supplies transported into California by others.

Gas Gathering Facilities

The Utility’s gas gathering system collects natural gas from third-party wells in northern and central California. During 2010, approximately 5% of the gas transported on the Utility’s system came from various California producers, with the balance coming from supplies transported into California by others. The natural gas well production is processed by producers to remove various impurities from the natural gas stream, and the Utility then odorizes the natural gas so that it may be detected in the event of a leak. The facilities include approximately 40 miles of gas gathering pipelines. The Utility receives gas well production at approximately 180 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 7 California counties. Approximately 123 MMcf per day of natural gas produced in northern California was delivered into the Utility’s gas gathering system during 2010.

Interstate and Canadian Natural Gas Transportation Services Agreements

In 2010, approximately 59% of the gas transported on the Utility’s system came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers’ service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States-Canada border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System. These companies’ pipeline systems connect at the border to the pipeline system owned by TransCanada’s Gas Transmission Northwest Corporation (“GTN”), which provides natural gas transportation services to a point of interconnection with the Utility’s natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility, the largest firm shipper on GTN’s pipeline, has three firm transportation agreements with GTN for these services.

During 2010, approximately 36% of the gas transported on the Utility’s system came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Company and El Paso Natural Gas Company to transport this natural gas from supply points in this region to interconnection points with the Utility’s natural gas transportation system in the area of California near Topock, Arizona.

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The following table shows certain information about the Utility’s firm natural gas transportation agreements in effect during 2010 to support the Utility’s needs for its core customers, including the contract quantities, contract durations, and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by the National Energy Board of Canada in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System, and by the FERC in all other cases. The Utility may, upon prior notice and with the CPUC’s approval, extend most of these natural gas transportation agreements. The Utility retains a right of first refusal or evergreen rights on most agreements, allowing renewal at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.

Pipeline	Expiration Date	Quantity MDth per day	Demand Charges                      for the Year Ended                      December 31, 2010                      (In millions)
TransCanada NOVA Gas Transmission, Ltd. (1)	Various	619	$40.1
TransCanada Foothills Pipe Lines Ltd., B.C. System (2)	Various	611	16.5
Gas Transmission Northwest Corporation (3)	Various	610	72.9
Transwestern Pipeline Company (4)	Various	177	19.7
El Paso Natural Gas Company (5)	Various	202	22.3

(1) As of December 31, 2010, the Utility had three active contracts with TransCanada NOVA Gas Transmission, Ltd. with expiration dates ranging from October 31, 2011 to October 31, 2020.

(2) As of December 31, 2010, the Utility had three active contracts with TransCanada Foothills Pipe Lines Ltd., B.C. System with expiration dates ranging from October 31, 2011 to October 31, 2012.

(3) As of December 31, 2010, the Utility had three active contracts with Gas Transmission Northwest Corporation with expiration dates ranging from October 31, 2011 to October 31, 2020.

(4) As of December 31, 2010, the Utility had two active contracts with Transwestern Pipeline Company with expiration dates ranging from February 28, 2011 to March 31, 2013.

(5) As of December 31, 2010, the Utility had two active contracts with El Paso Natural Gas Company with expiration dates ranging from June 30, 2012 to June 30, 2013.

In addition, in December 2008, the CPUC approved an agreement between the Utility and El Paso Corporation for the Utility to subscribe for firm service rights on El Paso Corporation’s proposed 680-mile 42-inch natural gas transmission pipeline (“Ruby Pipeline”) that would begin at the Opal Hub in Wyoming and terminate at the Malin, Oregon, interconnect, near California’s northern border. The Utility has subscribed for firm service rights for 375 MDth per day of which 250 MDth per day will serve the Utility’s core portfolio customers and 125 MDth per day will be subject to the Utility’s management of electric fuels used to generate electricity. The Ruby Pipeline will have an initial capacity of 1.5 Bcf per day and will connect Rocky Mountain natural gas producers with markets in northern California, Nevada, and the Pacific Northwest. Construction of the Ruby Pipeline began in July 2010 and is anticipated to be in service in June 2011.

Energy Efficiency, Public Purpose, and Other Programs

California law requires the CPUC to authorize certain levels of funding for public purpose programs related to energy efficiency, low-income energy efficiency, research and development, and renewable energy resources. California law also requires the CPUC to authorize funding for the California Solar Initiative and other self-generation programs, as discussed below. Additionally, the CPUC has authorized funding for demand response programs.

For 2010, the Utility collected authorized revenue requirements of $700 million from electric customers and $146 million from gas customers to fund public purpose and other programs. The CPUC is responsible for

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authorizing the programs, funding levels, and cost recovery mechanisms for the Utility’s operation of these programs. The CEC administers both the electric and natural gas public interest research and development programs and the renewable energy program on a statewide basis. In 2010, the Utility transferred $84 million from its revenue requirements to the CEC to fund these programs.

Energy Efficiency Programs

The Utility’s energy efficiency programs are designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances and other energy-using products. In 2010, the Utility collected authorized revenue requirements of $436 million to fund these programs from gas and electric customers. The CPUC has authorized a total of $1.3 billion to fund the Utility’s 2010-2012 energy efficiency programs, a 42% increase over 2006-2008 authorized funding levels. The CPUC has adopted a long-term energy efficiency strategic plan designed to encourage innovative market transformation activities, such as the pursuit of zero net energy buildings, in addition to traditional energy efficiency rebate programs.

The CPUC established an incentive ratemaking mechanism to encourage the California investor-owned utilities to promote energy efficiency and to meet the CPUC’s energy savings goals. In accordance with this mechanism, the CPUC has awarded the Utility incentive revenues totaling $104 million through December 31, 2010 based on the energy savings achieved through implementation of the Utility’s energy efficiency programs during the 2006 through 2008 program cycle. Applications for incentive awards for implementation of 2009 energy efficiency programs are due by June 30, 2011, to enable the CPUC to issue a final decision by the end of 2011.

It is uncertain what form of incentive ratemaking the CPUC will establish and what amount, if any, the Utility will be authorized to earn for future energy efficiency programs. For more information, see “Regulatory Matters — Energy Efficiency Programs and Incentive Ratemaking” in the 2010 Annual Report.

Demand Response Programs

Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use. The CPUC has authorized the Utility to collect $109 million to fund its 2009-2011 demand response programs. In addition, the CPUC has authorized the Utility to collect $179 million through June 1, 2011 to implement its multi-year air conditioning direct load control program. Customers who enroll in this program will allow the Utility to remotely control the temperature settings of their central air conditioners to temporarily decrease their energy usage during local or system emergencies.

Self-Generation Incentive Program and California Solar Initiative

The Utility administers the self-generation incentive program (“SGIP”) authorized by the CPUC to provide incentives to electricity customers who install certain types of clean or renewable distributed generation and energy storage resources that meet all or a portion of their onsite energy usage. The CPUC approved a budget for the extension of the SGIP of approximately $36 million in each of 2010 and 2011, with any carryover funds to be administered through 2015. In late 2006, the CPUC established the California Solar Initiative (“CSI”) to bring 1,940 MW of solar power on-line in California by 2017 and authorized the California investor-owned utilities to collect an additional $2.2 billion in the aggregate over the 2007 through 2016 period from their customers to fund customer incentives for the installation of retail solar energy projects to serve onsite load to meet this goal. Of the total amount authorized, the Utility has been allocated $946 million to fund customer incentives, research, development, and demonstration activities (with an emphasis on the demonstration of solar and solar-related technologies), and administration expenses. The California Legislature modified the CSI program to include participation of the California municipal utilities. The current overall objective of the CSI is to install 3,000 MW (through both investor-owned electric utilities and electric municipal utilities) through 2016.

Low-Income Energy Efficiency Programs and California Alternate Rates for Energy

The CPUC has authorized the Utility to collect approximately $417 million to support the Utility’s energy efficiency programs for low-income and fixed-income customers over 2009 through 2011. The Utility also provides

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a discount rate called the California Alternate Rates for Energy (“CARE”) for low-income customers. This rate subsidy is paid for by the Utility’s other customers. The extent of the subsidy, during any given year, for customers collectively depends upon the number of customers participating in the program and their actual energy usage. In 2010, the amount of this subsidy was approximately $825 million, including avoided customer surcharges. The CPUC also authorized the Utility to recover approximately $28 million in administrative costs relating to the CARE subsidy over 2009 through 2011.

Environmental Matters

General

The Utility is subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of activities, including the following:

• the discharge of pollutants into the air, water, and soil;

• the transportation, handling, storage and disposal of spent nuclear fuel;

• the identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting, remediation and emergency response in connection with hazardous and radioactive substances;

• the reporting and reduction of carbon dioxide (“CO2”) and other GHG emissions; and

• the environmental impacts of land use, including endangered species and habitat protection.

The penalties for violation of these laws and requirements can be severe and may include significant fines, damages, and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. To comply with these laws and requirements, the Utility may need to spend substantial amounts from time to time to construct, acquire, modify, or replace equipment, acquire permits and/or emission allowances or other emission credits for facility operations and clean-up, or decommission waste disposal areas at the Utility’s current or former facilities and at third-party sites where the Utility’s wastes may have been disposed.

The Utility’s estimated costs to comply with environmental laws and regulations are based on current estimates and assumptions that are subject to change. In addition, the Utility is likely to incur costs as it develops and implements strategies to mitigate the impact of its operations on the environment, including climate change and its foreseeable impact on the Utility’s future operations. The actual amount of costs that the Utility will incur is subject to many factors, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner’s responsibility, the availability of recoveries or contributions from third parties, and the development of market-based strategies to address climate change. Generally, the Utility has recovered the costs of complying with environmental laws and regulations in the Utility’s rates, subject to reasonableness review. Environmental costs associated with the clean-up of most sites that contain hazardous substances are subject to a special ratemaking mechanism described below under “Recovery of Environmental Remediation Costs.”

Air Quality and Climate Change

PG&E Corporation and the Utility believe the link between man-made GHG emissions and global climate change is clear and convincing and that mandatory GHG reductions are necessary. PG&E Corporation and the Utility believe the development of a market-based cap-and-trade system, in conjunction with successful energy efficiency and demand-side management programs and the development of renewable energy resources, can reduce GHG emissions while diversifying energy supply resources and minimizing costs to customers.

Regulation. The Utility’s electricity generation plants, natural gas pipeline operations, fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state

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and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide (“SO2”), nitrogen oxide (“NOx”) and particulate matter. At the federal level, the U.S. Environmental Protection Agency (“EPA”) is charged with implementation and enforcement of the Clean Air Act. At the state level, the CARB is the state agency charged with monitoring GHG levels and adopting regulations to implement and enforce the AB 32.

At the federal level, there have been several legislative attempts to address climate change through imposition of nationwide regulatory limits on GHG emissions but comprehensive federal legislation has not yet been enacted. In the absence of federal legislative action, the EPA has used its existing authority under the Clean Air Act to address GHG emissions, including establishing an annual GHG reporting requirement. In June 2010, the EPA adopted the final “tailoring rule” to phase-in permit requirements for construction of new sources of GHG emissions, such as power plants and natural gas compressor stations, if the GHG emissions from these sources would exceed certain thresholds. These permit requirements also apply to major modifications proposed to be made to existing facilities that emit GHGs that meet the threshold. The EPA rules require owners of these facilities to use the “best available control technology” to minimize GHG emissions. The uncertainty about what constitutes the “best available control technology” may cause permitting delays. Several of the EPA’s actions have been challenged in court and are not likely to be resolved until late 2011 or in 2012.

At the state level, AB 32 requires the gradual reduction of GHG emissions in California to the 1990 level by 2020 on a schedule beginning in 2012. The CARB established a state-wide GHG 1990 emissions baseline of 427 million metric tons of CO2 (or its equivalent) to serve as the 2020 emissions limit for the state of California. In December 2008, the CARB adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target set pursuant to AB 32. These recommendations include increasing renewable energy supplies, increasing energy efficiency goals, expanding the use of combined heat and power facilities, and developing a multi-sector cap-and-trade program. (For information about the CARB’s renewable energy requirements, see “Utility Operations-Electricity Resources- Renewable Generation Resources” above.)

The CARB also issued proposed cap-and-trade regulations for public comment in October 2010. The proposed regulations include provisions to establish state-wide caps on GHG emissions (for three 3-year compliance periods beginning January 1, from 2012 and ending December 31, 2020), allocate emission allowances (i.e., the rights to emit GHGs) among utilities and other industry participants, and permit the purchase and sale of emission allowances through a CARB-managed auction, among other provisions. After considering the comments that had been received, on December 16, 2010, the CARB directed its staff to prepare modified regulations and publish the modified regulations for one or more 15-day public comment and review periods. The modified regulations (with such further modifications as the CARB’s executive officer approves) will be submitted to the California Office of Administrative Law for final approval. If the regulations become effective, the first compliance period would begin on January 1, 2012 and apply to the electricity and industrial sectors. The second phase would begin on January 1, 2015 and would expand to include suppliers of natural gas and liquid fossil fuels. Before the new cap- and-trade program can become effective, a legal challenge to the CARB’s authority to implement its AB 32 scoping plan must be resolved. (See the section entitled “Environmental Matters” in the 2010 Annual Report.)

In addition to the requirements of AB 32, California Senate Bill 1368, enacted in 2006, prohibits any load-serving entity in California, including investor-owned electric utilities, from generating base-load electricity or entering into a long-term financial commitment to purchase base-load electricity generation unless the generating source complies with the CPUC-adopted GHG emission performance standard of 1,100 pounds of CO2 per MWh.

Climate Change Mitigation and Adaptation Strategies. During 2010, the Utility continued its programs to develop strategies to mitigate the impact of the Utility’s operations (including customer energy usage) on the environment and to develop its strategy to plan for the actions that it will need to take to adapt to the likely impacts that climate change will have on the Utility’s future operations. With respect to electric operations, climate scientists project that, sometime in the next several decades, climate change will lead to increased electricity demand due to more extreme and frequent hot weather events. Climate scientists also predict that climate change will result in significant reductions in snowpack in the Sierra Nevada Mountains. This impact could, in turn, affect PG&E’s hydroelectric generation. At this time, the Utility does not anticipate that reductions in Sierra Nevada snowpack will have a significant impact on its hydroelectric generation, due in large part to its adaptation strategies. For example,

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one adaptation strategy the Utility is developing is a combination of operating changes that may include, but are not limited to, higher winter carryover reservoir storage levels, reduced conveyance flows in canals and flumes in response to an increased portion of precipitation falling as rain and reduced discretionary reservoir water releases during the late spring and summer. If the Utility is not successful in fully adapting to projected reductions in snowpack over the coming decades, it may become necessary to replace some of its hydroelectricity from other sources, including GHG-emitting natural gas-fired power plants.

With respect to natural gas operations, the Utility has taken steps to reduce the release of methane, a GHG released as part of the delivery of natural gas. The Utility has replaced a substantial portion of its older cast iron and steel gas mains and implemented a technique called cross-compression, a process by which natural gas is transferred from one pipeline to another during large pipeline construction and repair projects. Cross-compression reduces the amount of natural gas vented to the atmosphere by 75% to 90%. In late 2008, the Utility also conducted focused surveys for high-volume gas leaks at its Topock and Kettleman compressor stations to reduce methane emissions.

The Utility believes its strategies to reduce GHG emissions—such as energy efficiency and demand response programs, infrastructure improvements, and the support of renewable energy development —are also effective strategies for adapting to the expected increased demand for electricity in extreme hot weather events likely to be caused by climate change. PG&E Corporation and the Utility are also assessing the benefits and challenges associated with various climate change policies and identifying how a comprehensive program can be structured to mitigate overall costs to customers and the economy as a whole while ensuring that the environmental objectives of the program are met.

Emissions Data

PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas. The Utility was a charter member of the California Climate Action Registry (“CCAR”) and has voluntarily reported its GHG emissions to CCAR on an annual basis from 2002 through 2008. In 2010, the Utility also voluntarily reported its 2009 GHG emissions to The Climate Registry (“TCR”), a successor non-profit to CCAR that is developing consistent reporting and measurement standards across industry sectors in North America. In 2010, the Utility also complied with AB 32’s annual GHG emission reporting requirement by reporting its 2009 GHG emissions to the CARB.

PG&E Corporation and the Utility also publish third-party-verified GHG emissions data in their annual Corporate Responsibility and Sustainability Report. As a result of the time necessary for a thorough, third-party verification of the Utility’s GHG emissions in accordance with the highest standards developed by TCR, preliminary emissions data for 2009 are the most recent data available. Final emissions data will be made publicly available by TCR on its website in February 2011 as well as reported by PG&E Corporation and the Utility in the next Corporate Responsibility and Sustainability Report expected to be posted to their websites in July 2011. For information about the sources of electric generation that the Utility delivered to customers in 2010, see “Electric Utility Operations-Electric Generation Resources” above.

Total 2009 GHG Emissions by Source Category

Source	Amount (per million metric tonnes CO2 – equivalent)
Delivered Electricity (1)		20.78
Electricity Transmission and Distribution Line Losses		0.97
Process and Fugitive Emissions from Natural Gas System		1.32
Gas Compressor Stations		0.31
Transportation (Fleet vehicles)		0.11
Facility Gas and Electricity Use		0.04
Electrical Equipment		0.06
Total		23.59

⁽¹⁾ Since the Utility purchases a portion of its electricity from the wholesale market, the Utility is not able to track some of its delivered electricity back to a specific generator. Therefore, there is some unavoidable uncertainty in the Utility’s total emissions and the Utility’s emission rate for delivered electricity. Emissions data for the Utility’s owned generation resources is shown below.

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Benchmarking Greenhouse Gas Emissions for Delivered Electricity

The Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2009 was 575 pounds of CO2 per MWh, which is a slight decrease from the 2008 emissions rate of 641 pounds of CO2 per MWh. The Utility’s 2009 emissions rate as compared to the national and California averages for electric utilities is shown in the following table:

	Amount (Pounds of CO2 per MWh)
U.S. Average (1)		1,329
California’s Average (1)		724
Pacific Gas and Electric Company (2)		575
(1) Source: Environmental Protection Agency eGRID 2007 Version 1.1, which contains year 2005 information configured to reflect the electric power industry’s current structure as of December 31, 2007. This is the most up-to-date information available from EPA. (2) Since the Utility purchases a portion of its electricity from the wholesale market, the Utility is not able to track some of its delivered electricity back to a specific generator. Therefore, there is some unavoidable uncertainty in the Utility’s total emissions and the Utility’s emission rate for delivered electricity.

Emissions Data for Utility-Owned Generation

In addition to GHG emissions data provided above, the table below sets forth information about the GHG and other emissions from the Utility’s owned generation facilities. The Utility’s owned generation (primarily nuclear and hydroelectric facilities) comprised approximately 36% of the Utility’s delivered electricity in 2009. The Utility’s retained fossil-fuel generation comprised less than 1% of the Utility’s delivered electricity in 2009.

	2009	2008
Total NOx Emissions (tons)	1,258	1,163
NOx Emissions Rates (pounds/MWh)
Fossil Plants	0.82	4.26
All Plants	0.09	0.09
Total SO2 Emissions (tons)	37	27
SO2 Emissions Rates (pounds/MWh)
Fossil- Plants	0.02	0.098
All Plants	0.0026	0.0021
Total CO2 Emissions (metric tons)	1,401,487	366,553
CO2 Emissions Rates (pounds/MWh)
Fossil Plants	1,016	1,554
All Plants	110	32
Other Emissions Statistics
Sulfur Hexafluoride (“SF6”) Emissions
Total SF6 Emissions (metric tons CO2-equivalent)	62,129	64,362
SF6 Emissions Leak Rate	1.7%	1.9%

Water Quality

The Utility’s Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act National Pollutant Discharge Elimination System (“NPDES”) permit issued by the Central Coast Regional Water Quality Control Board (“Central Coast Board”). This permit allows the Diablo Canyon

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power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon power plant’s discharge was not protective of beneficial uses. For more information, see the discussion below in “Item 3 — Legal Proceedings — Diablo Canyon Power Plant.”

On May 4, 2010, the California Water Resources Control Board (“Water Board”) adopted a policy on once-through cooling. The policy, effective October 1, 2010, 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 power 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. 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.

There is continuing uncertainty about the status of federal regulations issued under Section 316(b) of the Clean Water Act, which require that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. In July 2004, the EPA issued regulations to implement Section 316(b) intended to reduce impacts to aquatic organisms by establishing a set of performance standards for cooling water intake structures. These regulations provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The EPA regulations also allowed the use of environmental mitigation or restoration to meet compliance requirements in certain cases. Various parties separately challenged the EPA’s regulations and in January 2007, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”) issued a decision holding that environmental restoration cannot be used as a compliance option and that site-specific compliance variances based on a cost-benefit test cannot be used. The Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and in July 2007, the EPA suspended its regulations. The U.S. Supreme Court granted review of the cost-benefit question and in April 2009, issued a decision overturning the Second Circuit, finding the EPA’s use of a cost-benefit test reasonable. Depending on the form of the final regulations that may ultimately be adopted by the EPA, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. The EPA is not expected to issue draft revised regulations before March 2011. If the final regulations adopted by the EPA require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge.

Hazardous Waste Compliance and Remediation

The Utility’s facilities are subject to the requirements issued by the EPA under the Resource Conservation and Recovery Act (“RCRA”) and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), as well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site, and in some cases corporate successors to the operators or arrangers. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources,

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and the costs of required health studies. In the ordinary course of the Utility’s operations, the Utility generates waste that falls within CERCLA’s definition of hazardous substances and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

The Utility assesses, on an ongoing basis, measures that may be necessary to comply with federal, state, and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Utility has a comprehensive program to comply with hazardous waste storage, handling, and disposal requirements issued by the EPA under RCRA and state hazardous waste laws, and other environmental requirements.

The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws. These sites include former manufactured gas plant (“MGP”) sites; power plant sites; gas gathering sites; compressor stations; and sites where the Utility stores, recycles, and disposes of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site.

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. For more information about environmental remediation liabilities, see “Environmental Matters” and “Critical Accounting Polices” and Note 15 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report which information is incorporated herein by reference and included in Exhibit 13 to this report.

Generation Facilities

Operations at the Utility’s current and former generation facilities may have resulted in contaminated soil or groundwater. Although the Utility sold most of its geothermal and fossil fuel-fired plants, in many cases the Utility retained pre-closing environmental liability under various environmental laws. The Utility currently is investigating or remediating several such sites with the oversight of various governmental agencies. Additionally, the Utility’s Hunters Point power plant in San Francisco closed in May 2006 and is in the decommissioning process. The California Department of Toxic Substances Control (“DTSC”) approved the soil and groundwater remediation plan in June 2010 and remediation pursuant to the plan is underway. The Utility spent approximately $12 million in 2010 and estimates that it will spend approximately $33 million in 2011 for remediation at this site. Fossil fuel-fired Units 1 and 2 of the Utility’s Humboldt Bay power plant shut down in September 2010, and are now in the decommissioning process along with the nuclear Unit 3, which was shut down in 1976. The Utility has entered into a voluntary cleanup agreement with the DTSC and is currently completing a soil and groundwater investigation to determine what, if any, soil and groundwater remediation may be necessary.

Former Manufactured Gas Plant Sites

The Utility is assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain retired MGP sites. During their operation, from the mid-1800s through the early 1900s, MGPs produced lampblack and coal tar residues. The residues from these operations, which may remain at some sites, contain chemical compounds that now are classified as hazardous. The Utility has been coordinating with environmental agencies and third-party owners to evaluate and take appropriate action to mitigate any potential environmental concerns at 41 MGP sites that the Utility owned or operated in the past. Of these sites owned or operated by the Utility, 40 sites have been or are in the process of being investigated and/or remediated, and the Utility is developing a strategy to investigate and remediate the last site. The Utility spent approximately $35 million in 2010 and estimates it will spend approximately $37 million in 2011 and $51 million in 2012 on these sites.

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Third-Party Owned Disposal Sites

Under environmental laws, such as CERCLA, the Utility has been or may be required to take remedial action at third-party sites used for the disposal of waste from the Utility’s facilities, or to pay for associated clean-up costs or natural resource damages. The Utility is currently aware of two such sites where investigation or clean-up activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility substantially completed closure of the disposal facility, which was abandoned by its operator. The Utility was the major responsible party and led the remediation effort on behalf of the responsible parties. For the Casmalia disposal facility near Santa Maria, California, the Utility and several parties that sent waste to the site have entered into a court-approved agreement with the EPA that requires the Utility and the other parties to perform certain site investigation and remediation measures.

Natural Gas Compressor Stations

Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility has a comprehensive program to monitor a network of groundwater wells at both the Hinkley and Topock natural gas compressor stations. The Utility also owns the Kettleman natural gas compressor station but does not expect that it will incur any material expenditures related to remediation at this site.

At the Hinkley site, the Utility is cooperating with the Regional Water Quality Control Board (“RWQCB”) to evaluate and remediate the chromium groundwater plume. Measures have been implemented to control movement of the plume, while full-scale in-situ treatment systems operate to reduce the mass of the plume. An evaluation of the performance of these interim remedy measures, as well as possible future measures, is underway as part of the development of a final remediation plan. The Utility is working with the RWQCB to prepare an environmental impact report analyzing the potential impacts of the potential remedies for the site. In addition, the Utility is complying with the RWQCB’s order that the Utility provide bottled drinking water to all residents where well water contains levels of hexavalent chromium over regional background levels. The Utility also has instituted a program to purchase those properties where chromium levels exceed background levels or that are otherwise needed for remediation purposes. The Utility estimates that total acquisition costs will be $35 million, of which $15 million is forecasted to be spent in 2011 with the remaining amount forecasted to be spent in future years. Under applicable accounting rules, these property acquisition costs will be treated as remediation costs. In 2010, the Utility spent approximately $15 million on remediation activities at Hinkley, and currently estimates it will spend at least $31 million in 2011 (including property acquisition costs of $15 million) and $5 million in 2012. Remediation costs associated with the Hinkley natural gas compressor site are not recoverable from customers under the ratemaking mechanism discussed below nor are these costs recoverable from insurers.

At the Topock natural gas compressor station, located near Needles, California, the Utility has implemented interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of a hexavalent chromium plume toward the Colorado River, while regulatory agencies considered the Utility’s proposed final remediation plan. As a final remediation plan, the Utility has proposed an in-situ treatment project to inject ethanol into the groundwater to accelerate the microbial breakdown of hexavalent chromium into a non-toxic and non-soluble form of chromium. The proposed plan involves the construction of a significant number of additional injection and extraction wells and an associated piping system. In January 2011 the DTSC and United States Department of Interior approved the Utility’s proposal. While developing the plan the Utility consulted with various local Native American Tribes who claimed the project would negatively impact an area of cultural significance. One of the tribes, the Fort Mojave Indian Tribe, has questioned the adequacy of the environmental consideration of negative cultural impacts of the project and may file an objection to the DTSC’s approval by the March 2, 2011 due date.

In 2010, the Utility spent approximately $22 million for remediation activities at Topock. Assuming the Utility is permitted to implement the approved final remediation plan, the Utility currently estimates that it will spend at least $21 million in 2011 and $23 million in 2012. The Utility’s remediation costs for Topock are subject to the ratemaking mechanism described below.

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Recovery of Environmental Remediation Costs

The CPUC has approved a ratemaking mechanism under which the Utility is authorized to recover environmental costs associated with the clean-up of most sites that contain hazardous substances, including former MGP sites, third-party disposal sites, and natural gas compressor sites (other than the Hinkley site). This mechanism allows the Utility to include 90% of eligible hazardous substance cleanup costs in the Utility’s rates without a reasonableness review. Ten percent of any net insurance recoveries associated with hazardous waste remediation sites are assigned to the Utility’s customers. The balances of any insurance recoveries (90%) are retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. Any insurance recoveries above full cost reimbursement levels are allocated 60% to customers and 40% to the Utility. Finally, 10% of any recoveries from the Utility’s claims against third parties associated with hazardous waste remediation sites are retained by the Utility, with the remainder, 90% of any such recoveries, assigned to the Utility’s customers.

The CPUC has separately authorized the Utility to recover 100% of its remediation costs for decommissioning formerly owned fossil-fueled generation facilities and certain of the Utility’s transmission stations. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers.

Nuclear Fuel Disposal

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.

Because the DOE failed to develop a permanent storage site, the Utility obtained a permit from the NRC to build an on-site dry cask storage facility at Diablo Canyon to store spent fuel through at least 2024. The construction of the dry cask storage facility is complete. During 2009, the Utility moved all the spent nuclear fuel that was scheduled to be moved into dry cask storage. An appeal of the NRC’s issuance of the permit is still pending in the U.S. Court of Appeals for the Ninth Circuit. The appellants claim that the NRC failed to adequately consider environmental impacts of a potential terrorist attack at Diablo Canyon. The Ninth Circuit heard oral arguments on November 4, 2010. The Utility expects the court to issue a decision in 2011.

As a result of the DOE’s failure to build a 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 sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, on March 30, 2010, the U.S. Court of Federal Claims awarded the Utility $89 million. The DOE filed an appeal of this decision on May 28, 2010. On August 3, 2010, the Utility filed two complaints against the DOE in the U.S. Court of Federal Claims seeking to recover all costs incurred since 2005 to build on-site storage. The Utility estimates that it has incurred costs of at least $205 million since 2005. Amounts recovered from the DOE will be credited to customers.

Nuclear Decommissioning

The Utility’s nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay Unit 3. Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility makes contributions to trusts to provide for the eventual decommissioning of each nuclear unit. In the Utility’s 2005 Nuclear Decommissioning Cost Triennial Proceeding, which is used to determine the level of Utility trust contributions and related revenue requirement, the CPUC assumed that the eventual decommissioning of Diablo Canyon Unit 1 would be scheduled to begin in 2024 and be completed in 2044, that decommissioning of Diablo Canyon Unit 2 would be scheduled to begin in 2025 and be completed in 2041, and that decommissioning of Humboldt Bay Unit 3 would be scheduled to begin in 2009 and be completed in 2015. A

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premature shutdown of the Diablo Canyon units would increase the likelihood of an earlier start to decommissioning. The Utility’s decommissioning cost estimates are based on the 2005 decommissioning cost studies, prepared in accordance with CPUC requirements. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’s nuclear power plants. Actual decommissioning costs may vary from these estimates to the extent the assumptions on which the estimates are based (such as assumptions about decommissioning dates, regulatory requirements, technology, and costs of labor, materials, and equipment) differ from actual results. The Utility recovers its revenue requirements for estimated nuclear decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility’s nuclear facilities.

In April 2009, the Utility filed an application in the 2009 Nuclear Decommissioning Triennial Proceeding with new decommissioning cost estimates and other funding assumptions, such as projected cost escalation factors and projected earnings of the funds for 2010, 2011, and 2012. In July 2010, the CPUC issued a decision in the first phase of the proceeding to determine the annual revenue requirement for the decommissioning trust. The CPUC has not yet issued a decision in the second phase of the proceeding which is evaluating whether to broaden investment options available to the trusts. For more information about nuclear decommissioning, see Note 2 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.

Endangered Species

Many of the Utility’s facilities and operations are located in, or pass through, areas that are designated as critical habitats for federal, or state-listed endangered, threatened, or sensitive species. The Utility may be required to incur additional costs or be subjected to additional restrictions on operations if additional threatened or endangered species are listed or additional critical habitats are designated at or near the Utility’s facilities or operations. The Utility is seeking to secure “habitat conservation plans” to ensure long-term compliance with state and federal endangered species acts. The Utility expects that it will be able to recover costs of complying with state and federal endangered species acts through rates.

Electric and Magnetic Fields

Electric and magnetic fields (“EMFs”) naturally result from the generation, transmission, distribution, and use of electricity. In November 1993, the CPUC adopted an interim EMF policy for California energy utilities that, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMFs from new or upgraded utility facilities. California energy utilities were required to fund an EMF education program and an EMF research program managed by the California Department of Health Services. In October 2002, the California Department of Health Services released its report to the CPUC and the public, based primarily on its review of studies by others, evaluating the possible risks from EMFs. The report’s conclusions contrast with other recent reports by authoritative health agencies in that the California Department of Health Services’ report has assigned a higher probability to the possibility of a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis, and miscarriages.

On January 26, 2006, the CPUC issued a decision that affirms the CPUC’s “low-cost/no-cost, prudent avoidance” policy to reduce EMF exposure for new utility transmission and substation projects. The CPUC ordered the continued use of a 4% of project cost benchmark for EMF reduction measures. The CPUC also reaffirmed that it has exclusive jurisdiction with respect to utility EMF matters.

The Utility currently is not involved in third-party litigation concerning EMFs. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMFs from power lines. In a case involving allegations of personal injury, a California appeals court held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMFs, and barred plaintiffs’ personal injury claims. The California Supreme Court declined to hear the plaintiffs’ appeal of this decision.

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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 “Risk Factors” in the MD&A in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The Utility owns or has obtained the right to occupy and/or use real property comprising the Utility’s electricity and natural gas distribution facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, all of which are described above under “Electric Utility Operations” and “Natural Gas Utility Operations” which information is incorporated herein by reference. In total, the Utility occupies 9.8 million square feet of real property, including 8.5 million square feet that the Utility owns. Of the 9.8 million square feet of occupied real property, approximately 1.7 million square feet represent the Utility’s corporate headquarters located in several Utility-owned buildings in San Francisco, California. The Utility occupies or uses real property that it does not own primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental authorities.

The Utility currently owns approximately 167,000 acres of land, approximately 140,000 acres of which it will encumber with conservation easements and/or donate to public agencies or non-profit conservation organizations under the Chapter 11 Settlement Agreement. Approximately 75,000 acres of this land may be donated in fee and encumbered with conservation easements. The remaining land contains the Utility’s or a joint licensee’s hydroelectric generation facilities or is otherwise used for utility operations and will only be encumbered with conservation easements. As contemplated in the Chapter 11 Settlement Agreement, the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship Council (“Council”) to oversee the development and implementation of a Land Conservation Plan (“LCP”) that will articulate the long-term management objectives for the 140,000 acres. The Council is governed by an 18-member board of directors that represents a range of diverse interests, including the CPUC, California environmental agencies, organizations representing underserved and minority constituencies, agricultural and business interests, and public officials. The Utility has appointed 1 out of 18 members of the board of directors of the Council. In December 2007, the Council adopted the LCP and submitted it to the Utility. The Utility has accepted the LCP and will seek authorization from the CPUC, the FERC, and other approving entities to proceed with the transactions necessary to implement the LCP.

PG&E Corporation also leases approximately 74,000 square feet of office space from a third party in San Francisco, California. This lease expires in 2012.

Item 3. Legal Proceedings

In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business. For more information regarding PG&E Corporation’s and the Utility’s liability for legal matters, see Note 15 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which discussion is incorporated into this Item 3 by reference.

Diablo Canyon Power Plant

The Utility’s Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act permit issued by the Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Utility’s Diablo Canyon power plant’s discharge was not protective of beneficial uses.

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In October 2000, the Utility and the Central Coast Board reached a tentative settlement under which the Central Coast Board agreed to find that the Utility’s discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available, as defined in the federal Clean Water Act. As part of the tentative settlement, the Utility agreed to take measures to preserve certain acreage north of the plant and to fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the settlement agreement. On June 17, 2003, the settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General’s Office. A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon’s NPDES permit.

At its July 10, 2003 meeting, the Central Coast Board did not renew the NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published the scientists’ draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists’ recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers.

On May 4, 2010, the Water Board adopted a policy on once-through cooling. The policy, which is subject to approval by the California Office of Administrative Law, 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 power 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 policy could affect future negotiations between the Water Board and the Utility regarding the status of the 2003 settlement agreement.

PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on their Utility’s financial condition or results of operations.

Litigation Related to the San Bruno Accident

As of February 8, 2011, 59 lawsuits on behalf of approximately 177 plaintiffs, including two class action lawsuits, have been filed by residents of San Bruno in San Mateo County Superior Courts against the Utility, and in some cases, against PG&E Corporation. In addition, five lawsuits on behalf of 11 plaintiffs have been filed by residents of San Bruno in the San Francisco County Superior Court against the Utility, and in some cases, against PG&E Corporation. These lawsuits seek to recover compensation for personal injury and property damage and seek other relief. Each of the class action lawsuits include a demand that the $100 million the Utility announced would be available for assistance be placed under court supervision, and also allege causes of action for strict liability, negligence, public nuisance, private nuisance, and declaratory relief. One of the class action lawsuits was filed by Steve Dare and the other was filed by Danielle Ditrapani. The Utility has filed a petition on behalf of PG&E Corporation and the Utility to coordinate these lawsuits in the San Mateo County Superior Court. In its statement in support of coordination, the Utility has stated that it is prepared to enter into early mediation in an effort to resolve claims with those plaintiffs willing to do so. A hearing is scheduled for February 24, 2011.

Another lawsuit was filed in San Mateo County Superior Court as a purported shareholder derivative lawsuit to seek recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims.

The Utility maintains liability insurance for damages in the approximate amount of $992 million in excess of a $10 million deductible. Although PG&E Corporation and the Utility currently consider it likely that most of the

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costs the Utility incurs for third-party claims relating to the San Bruno Accident will ultimately be covered by this insurance, no amounts for insurance recoveries have been recorded as of December 31, 2010. PG&E Corporation and the Utility are unable to predict the amount and timing of such recoveries.

For discussion of other third-party claims relating to the San Bruno accident, see Note 15 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which discussion is incorporated into this Item  3 by reference.

Pending Investigations of the San Bruno and Rancho Cordova Accidents

For discussion of the pending investigations of the San Bruno accident and the Rancho Cordova accident, see Note 15 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which discussion is incorporated into this Item  3 by reference.

Item 4. [Removed and Reserved]

EXECUTIVE OFFICERS OF THE REGISTRANTS

The names, ages and positions of PG&E Corporation “executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934 (“Exchange Act”) at February 1, 2011 were as follows.

Name	Age	Position
Peter A. Darbee	58	Chairman of the Board, Chief Executive Officer, and President
Kent M. Harvey	52	Senior Vice President and Chief Financial Officer
Christopher P. Johns	50	President, Pacific Gas and Electric Company
Hyun Park	49	Senior Vice President and General Counsel
Greg S. Pruett	53	Senior Vice President, Corporate Affairs
Rand L. Rosenberg	57	Senior Vice President, Corporate Strategy and Development
John R. Simon	46	Senior Vice President, Human Resources

All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years through February 1, 2011, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.

Name	Position	Period Held Office
Peter A. Darbee	Chairman of the Board, Chief Executive Officer, and President	September 19, 2007 to present
	President and Chief Executive Officer, Pacific Gas and Electric Company	September 5, 2008 to July 31, 2009
	Chairman of the Board and Chief Executive Officer	July 1, 2007 to September 18, 2007
	Chairman of the Board, Chief Executive Officer, and President	January 1, 2006 to June 30, 2007
	Chairman of the Board, Pacific Gas and Electric Company	January 1, 2006 to May 31, 2007
Kent M. Harvey	Senior Vice President and Chief Financial Officer	August 1, 2009 to present
	Senior Vice President, Financial Services, Pacific Gas and Electric Company	August 1, 2009 to present
	Senior Vice President and Chief Risk and Audit Officer	October 1, 2005 to July 31, 2009
Christopher P. Johns	President, Pacific Gas and Electric Company	August 1, 2009 to present
	Senior Vice President and Chief Financial Officer	May 1, 2009 to July 31, 2009

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Name	Position	Period Held Office
	Senior Vice President, Financial Services, Pacific Gas and Electric Company	May 1, 2009 to July 31, 2009
	Senior Vice President, Chief Financial Officer, and Treasurer	October 4, 2005 to April 30, 2009
	Senior Vice President and Treasurer, Pacific Gas and Electric Company	June 1, 2007 to April 30, 2009
	Senior Vice President, Chief Financial Officer, and Treasurer, Pacific Gas and Electric Company	October 1, 2005 to May 31, 2007
Hyun Park	Senior Vice President and General Counsel	November 13, 2006 to present
	Vice President, General Counsel, and Secretary, Allegheny Energy, Inc.	April 5, 2005 to October 17, 2006
Greg S. Pruett	Senior Vice President, Corporate Affairs	November 1, 2009 to present
	Senior Vice President, Corporate Affairs, Pacific Gas and Electric Company	November 1, 2009 to present
	Senior Vice President, Corporate Relations	November 1, 2007 to October 31, 2009
	Senior Vice President, Corporate Relations, Pacific Gas and Electric Company	March 1, 2009 to October 31, 2009
	Vice President, Corporate Relations	March 1, 2007 to October 31, 2007
	Vice President, Communications and Marketing, American Gas Association	April 10, 2006 to February 23, 2007
Rand L. Rosenberg	Senior Vice President, Corporate Strategy and Development	November 1, 2005 to present
John R. Simon	Senior Vice President, Human Resources	April 16, 2007 to present
	Senior Vice President, Human Resources, Pacific Gas and Electric Company	April 16, 2007 to present
	Executive Vice President, Global Human Capital, TeleTech Holdings, Inc.	March 21, 2006 to April 13, 2007
	Senior Vice President, Human Capital, TeleTech Holdings, Inc.	July 31, 2001 to March 20, 2006

The names, ages and positions of the Utility’s “executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at February 1, 2011 were as follows:

Name	Age	Position
Peter A. Darbee	58	Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation
Christopher P. Johns	50	President
John S. Keenan	62	Senior Vice President and Chief Operating Officer
Desmond A. Bell	48	Senior Vice President, Shared Services and Chief Procurement Officer
Thomas E. Bottorff	57	Senior Vice President, Regulatory Relations
Helen A. Burt	54	Senior Vice President and Chief Customer Officer
John T. Conway	53	Senior Vice President, Energy Supply and Chief Nuclear Officer
Kent M. Harvey	52	Senior Vice President, Financial Services
Hyun Park	49	Senior Vice President and General Counsel, PG&E Corporation
Greg S. Pruett	53	Senior Vice President, Corporate Affairs
Edward A. Salas	54	Senior Vice President, Engineering and Operations
John R. Simon	46	Senior Vice President, Human Resources
Fong Wan	49	Senior Vice President, Energy Procurement
Geisha J. Williams	49	Senior Vice President, Energy Delivery
Sara A. Cherry	42	Vice President, Finance and Chief Financial Officer

All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through February 1, 2011, the executive officers of the Utility had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.

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Name	Position	Period Held Office
Peter A. Darbee	Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation	September 19, 2007 to present
	President and Chief Executive Officer	September 5, 2008 to July 31, 2009
	Chairman of the Board and Chief Executive Officer, PG&E Corporation	July 1, 2007 to September 18, 2007
	Chairman of the Board	January 1, 2006 to May 31, 2007
	Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation	January 1, 2006 to June 30, 2007
Christopher P. Johns	President	August 1, 2009 to present
	Senior Vice President, Financial Services	May 1, 2009 to July 31, 2009
	Senior Vice President and Chief Financial Officer, PG&E Corporation	May 1, 2009 to July 31, 2009
	Senior Vice President and Treasurer	June 1, 2007 to April 30, 2009
	Senior Vice President, Chief Financial Officer, and Treasurer, PG&E Corporation	October 4, 2005 to April 30, 2009
	Senior Vice President, Chief Financial Officer, and Treasurer	October 1, 2005 to May 31, 2007
John S. Keenan	Senior Vice President and Chief Operating Officer	January 1, 2008 to present
	Senior Vice President, Generation and Chief Nuclear Officer	December 19, 2005 to December 31, 2007
Desmond A. Bell	Senior Vice President, Shared Services and Chief Procurement Officer	October 1, 2008 to present
	Vice President, Shared Services and Chief Procurement Officer	March 1, 2008 to September 30, 2008
	Vice President and Chief of Staff	March 19, 2007 to February 29, 2008
	Vice President, Parts Logistics, Bombardier Aerospace	April 2003 to September 2006
Thomas E. Bottorff	Senior Vice President, Regulatory Relations	October 14, 2005 to present
Helen A. Burt	Senior Vice President and Chief Customer Officer	February 27, 2006 to present
	Management Consultant, The Burt Group	January 2003 to February 2006
John T. Conway	Senior Vice President, Energy Supply and Chief Nuclear Officer	April 1, 2009 to present
	Senior Vice President, Generation and Chief Nuclear Officer	October 1, 2008 to March 31, 2009
	Senior Vice President and Chief Nuclear Officer	March 1, 2008 to September 30, 2008
	Site Vice President, Diablo Canyon Power Plant	May 29, 2007 to February 29, 2008
	Site Vice President, Monticello Nuclear Plant, Nuclear Management Company	May 2005 to May 2007
Kent M. Harvey	Senior Vice President, Financial Services	August 1, 2009 to present
	Senior Vice President and Chief Financial Officer, PG&E Corporation	August 1, 2009 to present
	Senior Vice President and Chief Risk and Audit Officer, PG&E Corporation	October 1, 2005 to July 31, 2009
Hyun Park	Senior Vice President and General Counsel, PG&E Corporation	November 13, 2006 to present
	Vice President, General Counsel, and Secretary, Allegheny Energy, Inc.	April 5, 2005 to October 17, 2006
Greg S. Pruett	Senior Vice President, Corporate Affairs	November 1, 2009 to present
	Senior Vice President, Corporate Affairs, PG&E Corporation	November 1, 2009 to present
	Senior Vice President, Corporate Relations	March 1, 2009 to October 31, 2009

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Name	Position	Period Held Office
	Senior Vice President, Corporate Relations, PG&E Corporation	November 1, 2007 to October 31, 2009
	Vice President, Corporate Relations, PG&E Corporation	March 1, 2007 to October 31, 2007
	Vice President, Communications and Marketing, American Gas Association	April 10, 2006 to February 23, 2007
Edward A. Salas	Senior Vice President, Engineering and Operations	April 11, 2007 to present
	Staff Vice President, Network Planning, Verizon Wireless	May 2004 to April 2007
John R. Simon	Senior Vice President, Human Resources	April 16, 2007 to present
	Senior Vice President, Human Resources, PG&E Corporation	April 16, 2007 to present
	Executive Vice President, Global Human Capital, TeleTech	March 21, 2006 to April 13, 2007
	Senior Vice President, Human Capital, TeleTech Holdings, Inc.	July 13, 2001 to March 20, 2006
Fong Wan	Senior Vice President, Energy Procurement	October 1, 2008 to present
	Vice President, Energy Procurement	January 9, 2006 to September 30, 2008
Geisha J. Williams	Senior Vice President, Energy Delivery	December 1, 2007 to present
	Vice President, Power Systems, Distribution, Florida Power and Light Company	July 2003 to July 2007
Sara A. Cherry	Vice President, Finance and Chief Financial Officer	March 1, 2010 to present
	Senior Director, Internal Auditing	October 1, 2009 to February 28, 2010
	Director of Internal Auditing and Compliance	February 3, 2009 to September 30, 2009
	Chief Financial Officer of Langer, Inc., a medical and personal care products company	September 18, 2006 to December 5, 2006
	Director, Management Reporting, Pacific Gas and Electric Company	January 2005 to January 2006

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

As of February 10, 2011, there were 75,862 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed on the New York Stock Exchange and the Swiss stock exchanges. The high and low sales prices of PG&E Corporation common stock for each quarter of the two most recent fiscal years are set forth under the heading “Quarterly Consolidated Financial Data (Unaudited)” in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report. Information about the frequency and amount of dividends on common stock declared by PG&E Corporation and the Utility is set forth in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and in Note 6 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report. A discussion of the restrictions on the payment of dividends with respect to PG&E Corporation’s and the Utility’s common stock is set forth under the section of MD&A entitled “Liquidity and Financial Resources — Dividends” and Note 6 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.

Sales of Unregistered Equity Securities

During the quarter ended December 31, 2010, PG&E Corporation made equity contributions totaling $20 million to the Utility in order to maintain the Utility’s 52% common equity target authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures. PG&E Corporation did not make any sales of unregistered equity securities during 2010.

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Issuer Purchases of Equity Securities

During the quarter ended December 31, 2010, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the fourth quarter of 2010, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

Item 6. Selected Financial Data

A summary of selected financial information, for each of PG&E Corporation and the Utility for each of the last five fiscal years, is set forth under the heading “Selected Financial Data” in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit  13 to this report.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

A discussion of PG&E Corporation’s and the Utility’s consolidated financial condition and results of operations is set forth under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2010 Annual Report, which discussion is incorporated by reference and included in Exhibit 13 to this report.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Information responding to Item 7A appears in the 2010 Annual Report under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities,” and under Notes 10 and 11 of the Notes to the Consolidated Financial Statements of the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.

Item 8. Financial Statements and Supplementary Data

Information responding to Item 8 appears in the 2010 Annual Report under the following headings for PG&E Corporation: “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Equity;” under the following headings for Pacific Gas and Electric Company: “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders’ Equity;” and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: “Notes to the Consolidated Financial Statements,” “Quarterly Consolidated Financial Data (Unaudited),” and “Reports of Independent Registered Public Accounting Firm,” which information is incorporated by reference and included in Exhibit  13 to this report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of December 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 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 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,

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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 December 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.

Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting. Management’s report, together with the report of the independent registered public accounting firm, appears in the 2010 Annual Report under the heading “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm,” which information is incorporated by reference and included in Exhibit 13 to this report.

Item 9B. Other Information

Elimination of Excise Tax Gross-Up Payments for Officers

On February 15, 2011, the Compensation Committee of the PG&E Corporation Board of Directors amended the PG&E Corporation Officer Severance Policy (Officer Severance Policy) to reduce the benefits available to certain officers under the Officer Severance Policy. Currently, the Officer Severance Policy provides enhanced change-in-control (as defined in the Officer Severance Policy) severance benefits to officers of PG&E Corporation at the Senior Vice President level or higher, and to the principal executive officer of any entity listed in the Officer Severance Policy, which typically includes PG&E Corporation’s primary subsidiaries, including Pacific Gas and Electric Company (Covered Officers). The Internal Revenue Code imposes an excise tax on change-in-control severance benefits if the value equals or exceeds a safe harbor limit equal to three times a recipient’s average annualized income. The Officer Severance Policy reimburses the Covered Officers for excise taxes levied upon the change-in-control severance benefits.

The amendments to the Officer Severance Policy will eliminate excise tax gross-up payments for severance benefits triggered by a change in control (1) for current Covered Officers, effective three years after the current Covered Officers are given notice of the change, and (2) for executive officers who become eligible to receive change-in-control severance benefits under the Officer Severance Policy on or after February 15, 2011. Under the amended Officer Severance Policy, a Covered Officer will receive severance that results in the best after-tax benefit to the Covered Officer, either by receiving the full change-in-control severance benefit with the excise tax paid by the Covered Officer, or by receiving a reduced severance calculated in a manner that results in a total severance benefit below the Internal Revenue Code’s safe harbor limit described above. There are no other policies, arrangements, or agreements that provide for excise tax gross-ups to any current officers of PG&E Corporation or Pacific Gas and Electric Company.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information regarding executive officers of PG&E Corporation and the Utility is included above in a separate item captioned “Executive Officers of the Registrants” at the end of Part I of this report. Other information regarding directors is included under the heading “Nominees for Directors of PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference. Information regarding compliance with Section 16 of the Exchange Act is included under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

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Website Availability of Code of Ethics, Corporate Governance and Other Documents

The following documents are available both on PG&E Corporation’s website www.pgecorp.com, and the Utility’s website, www.pge.com: (1) the codes of conduct and ethics adopted by PG&E Corporation and the Utility applicable to their respective directors and employees, including their respective Chief Executive Officers, Chief Financial Officers, Controllers and other executive officers, (2) PG&E Corporation’s and the Utility’s corporate governance guidelines, and (3) key Board Committee charters, including charters for the companies’ Audit Committees and the PG&E Corporation Nominating and Governance Committee and Compensation Committee.

If any amendments are made to, or any waivers are granted with respect to, provisions of the codes of conduct and ethics adopted by PG&E Corporation and the Utility that apply to their respective Chief Executive Officers, Chief Financial Officers, or Controllers, the company whose code is so affected will disclose the nature of such amendment or waiver on its respective website and any waivers to the code will be disclosed in a Current Report on Form 8-K filed within four business days of the waiver.

Procedures for Shareholder Recommendations of Nominees to the Boards of Directors

During 2010 there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or Pacific Gas and Electric Company’s Boards of Directors.

Audit Committees and Audit Committee Financial Expert

Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial expert” as defined by the SEC is included under the heading “Corporate Governance – Board Committee Duties and Composition – Audit Committees” and “Corporate Governance – Board Committee Duties and Composition – Committee Membership Requirements” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Item 11. Executive Compensation

Information responding to Item 11, for each of PG&E Corporation and the Utility, is included under the headings “Compensation Discussion and Analysis (CD&A),” “Compensation Committee Report,” “Summary Compensation Table - 2010,” “Grants of Plan-Based Awards in 2010,” “Outstanding Equity Awards at Fiscal Year End - 2010,” “Option Exercises and Stock Vested During 2010,” “Pension Benefits - 2010,” “Non-Qualified Deferred Compensation,” “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” and “2010 Director Compensation” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information regarding the beneficial ownership of securities for each of PG&E Corporation and the Utility, is included under the heading “Security Ownership of Management” and under the heading “Other Information - Principal Shareholders” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

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Equity Compensation Plan Information

The following table provides information as of December 31, 2010 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation’s existing equity compensation plans.

Plan Category	(a) Number of Securities to             be Issued Upon Exercise of Outstanding Options, Warrants and Rights	(b) Weighted Average Exercise Price of             Outstanding Options, Warrants and Rights	(c) Number of Securities Remaining Available for Future Issuance Under         Equity Compensation Plans (Excluding Securities Reflected in Column(a))
Equity compensation plans approved by shareholders	3,842,313(1)	$25.16	7,856,348(2)
Equity compensation plans not approved by shareholders	—	—	—
Total equity compensation plans	3,842,313(1)	$25.16	7,856,348(2)

(1) Includes 2,472,302 phantom stock units, restricted stock units and performance shares. The weighted average exercise price reported in column (b) does not take these awards into account. The 1,219,940 performance shares included in this total reflects the number of shares that would be issued should PG&E Corporation achieve the maximum performance target for the applicable three-year period. For a description of these performance shares, see Note 6 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.

(2) Represents the total number of shares available for issuance under the PG&E Corporation’s Long-Term Incentive Program (“LTIP”) and the PG&E Corporation 2006 Long-Term Incentive Plan (“2006 LTIP”) as of December 31, 2010. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock, and phantom stock. The LTIP expired on December 31, 2005. The 2006 LTIP, which became effective on January 1, 2006, authorizes up to 12 million shares to be issued pursuant to awards granted under the 2006 LTIP. Outstanding stock-based awards granted under the 2006 LTIP include stock options, restricted stock, restricted stock units, phantom stock and performance shares. For a description of the LTIP and the 2006 LTIP, see Note 6 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information responding to Item 13, for each of PG&E Corporation and the Utility, is included under the headings “Related Person Transactions,” “Review, Approval, and Ratification of Related Person Transactions” and “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company – Director Independence and Qualifications” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Item 14. Principal Accountant Fees and Services

Information responding to Item 14, for each of PG&E Corporation and the Utility, is included under the heading “Information Regarding the Independent Registered Public Accounting Firm for PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) The following documents are filed as a part of this report:

1. The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are contained in the 2010 Annual Report and are incorporated by reference in this report:

Consolidated Statements of Income for the Years Ended December 31, 2010, 2009, and 2008 for each of PG&E Corporation and Pacific Gas and Electric Company.

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Consolidated Balance Sheets at December 31, 2010 and 2009 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009, and 2008 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Equity for the Years Ended December 31, 2010, 2009, and 2008 for PG&E Corporation.

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2010, 2009, and 2008 for Pacific Gas and Electric Company.

Notes to the Consolidated Financial Statements.

Quarterly Consolidated Financial Data (Unaudited).

Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).

2. The following financial statement schedules and report of independent registered public accounting firm are filed as part of this report:

Reports of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).

I—Condensed Financial Information of Parent as of December 31, 2010 and 2009 and for the Years Ended December 31, 2010, 2009, and 2008.

II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2010, 2009, and 2008.

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.

3. Exhibits required by Item 601 of Regulation S-K:

Exhibit     Number	Exhibit Description
2.1	Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company’s Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1)
2.2	Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company’s Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2)
3.1	Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
3.2	Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)

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Exhibit     Number	Exhibit Description
3.3	Bylaws of PG&E Corporation amended as of September 16, 2009 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2009 (File No. 1-12609), Exhibit 3.1)
3.4	Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
3.5	Bylaws of Pacific Gas and Electric Company amended as of February 17, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2009 (File No. 1-2348), Exhibit 3.5)
4.1	Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
4.2	First Supplemental Indenture dated as of March 13, 2007 relating to the Utility’s issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
4.3	Second Supplemental Indenture dated as of December 4, 2007 relating to the Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (file No. 1-2348), Exhibit 4.1)
4.4	Third Supplemental Indenture dated as of March 3, 2008 relating to the Utility’s issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 3, 2008 (File No. 1-2348), Exhibit 4.1)
4.5	Fourth Supplemental Indenture dated as of October 21, 2008 relating to the Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 21, 2008 (File No. 1-2348), Exhibit 4.1)
4.6	Fifth Supplemental Indenture dated as of November 18, 2008 relating to the Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25% Senior Notes due December 1, 2013 and $200 million principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2008 (File No. 1-2348), Exhibit 4.1)
4.7	Sixth Supplemental Indenture, dated as of March 6, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1)
4.8	Seventh Supplemental Indenture dated as of June 11, 2009 relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due June 10, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 11, 2009 (File No. 1-2348), Exhibit 4.1)
4.9	Eighth Supplemental Indenture dated as of November 18, 2009 relating to the issuance of $550,000,000 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 Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1)

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Exhibit     Number	Exhibit Description
4.10	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 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)
4.11	Tenth Supplemental Indenture dated as of September 15, 2010 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1)
4.12	Eleventh Supplemental Indenture dated as of October 12, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due October 11, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 12, 2010 (File No. 1-2348), Exhibit 4.1)
4.13	Twelfth Supplemental Indenture dated as of November 18, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 (File No. 1-2348), Exhibit 4.1)
4.14	Senior Note Indenture related to PG&E Corporation’s 5.75% Senior Notes due April 1, 2014, dated as of March 12, 2009, between PG&E Corporation and Deutsche Bank Trust Company Americas as Trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.1)
4.15	First Supplemental Indenture, dated as of March 12, 2009 relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 5.75% Senior Notes due April 1, 2014 (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.2)
10.1	Credit Agreement dated June 8, 2010, among (1) Pacific Gas and Electric Company, as borrower, (2) Wells Fargo Bank, N.A., as administrative agent and a lender, (3) The Royal Bank of Scotland plc, as syndication agent and a lender, (4) Banco Bilbao Vizcaya Argentaria, S.A., New York Branch, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, and U.S. Bank, N.A., as documentation agents and lenders, and (5) the following other lenders: Bank of America, N.A., Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, New York Branch, Goldman Sachs Bank USA, Mizuho Corporate Bank (USA), Morgan Stanley Bank, N.A., Royal Bank of Canada, UBS Loan Finance LLC, Citibank, N.A., East West Bank, RBC Bank (USA), JPMorgan Chase Bank, N.A., and The Northern Trust Company. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2010 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.2	Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)

52

Exhibit     Number	Exhibit Description
10.3	Amendment and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman Brothers Bank, FSB has been removed as a lender under the Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007, filed as Exhibit 10.1 above (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.4	Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentation agents and lenders, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)
10.5	Amendment and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman Brothers Bank, FSB has been removed as a lender under the Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentation agents and lenders, and other lenders, dated February 26, 2007, filed as Exhibit 10.3 above (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)
10.6	Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99)
10.7	Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)
10.8	Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9)
*10.9	PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)
*10.10	PG&E Corporation 2005 Supplemental Retirement Savings Plan effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009 and as further amended with respect to investment options effective as of July 13, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009) (File No. 1-12609), Exhibit 10.9
*10.11	Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)

53

Exhibit     Number	Exhibit Description
*10.12	Amended and Restated Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.11)
*10.13	Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12)
*10.14	Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005) (File No. 1-12609), Exhibit 10.18)
*10.15	Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006) (File No. 1-12609), Exhibit 10.18)
*10.16	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and John S. Keenan dated November 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.21)
*10.17	Separation Agreement between Pacific Gas and Electric Company and Barbara Barcon effective March 4, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.1)
*10.18	Separation Agreement between PG&E Corporation and Nancy E. McFadden effective February 23, 2011
*10.19	PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.24)
*10.20	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2010 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.21)
*10.21	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2011
*10.22	Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.27)
*10.23	Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.28)
*10.24	PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.1)
*10.25	Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.30)
*10.26	Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)

54

Exhibit     Number	Exhibit Description
*10.27	Amendment to Postretirement Life Insurance Plan of the Pacific Gas and Electric Company dated December 30, 2008 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.32)
*10.28	PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)
*10.29	Resolution of the PG&E Corporation Board of Directors dated September 17, 2008, adopting director compensation arrangement effective January 1, 2009 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609 and File No. 12348), Exhibit 10.36)
*10.30	Resolution of the Pacific Gas and Electric Company Board of Directors dated September 17, 2008, adopting director compensation arrangement effective January 1, 2009 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609 and File No. 12348), Exhibit 10.37)
*10.31	Resolution of the PG&E Corporation Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011
*10.32	Resolution of the Pacific Gas and Electric Company Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011
*10.33	PG&E Corporation 2006 Long-Term Incentive Plan, as amended through December 15, 2010
*10.34	PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
*10.35	Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.39)
*10.36	Form of Restricted Stock Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.5)
*10.37	Form of Amendment to Restricted Stock Agreements for grants made between January 2005 and March 2008 (amendments to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.45)
*10.38	Form of Restricted Stock Unit Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.2)
*10.39	Form of Performance Share Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.3)
*10.40	Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.2)

55

Exhibit     Number	Exhibit Description
*10.41	Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.3)
*10.42	Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1)
*10.43	Form of Performance Share Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.44)
*10.44	Form of Performance Share Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.6)
*10.45	Form of Amended and Restated Performance Share Agreement for 2007 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.52)
*10.46	Form of Amended and Restated Performance Share Agreement for 2008 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.53)
*10.47	PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.2)
*10.48	PG&E Corporation 2010 Executive Stock Ownership Guidelines as adopted September 14, 2010, effective January 1, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.3)
*10.49	PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.48)
*10.50	PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2009 (amended to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.56)
*10.51	PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011
*10.52	PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
*10.53	Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 (amendment to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58)
*10.54	PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)
*10.55	PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39)

56

Exhibit     Number	Exhibit Description
*10.56	PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective as of February 17, 2010 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.54)
*10.57	Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
*10.58	Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)
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
13	The following portions of the 2010 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: “Selected Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” financial statements of PG&E Corporation entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders’ Equity,” “Notes to the Consolidated Financial Statements,” “Quarterly Consolidated Financial Data (Unaudited),” “Management’s Report on Internal Control Over Financial Reporting,” and “Report of Independent Registered Public Accounting Firm.”
21	Subsidiaries of the Registrant
23	Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1	Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2	Powers of Attorney
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	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	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
***101.INS	XBRL Instance Document
***101.SCH	XBRL Taxonomy Extension Schema Document
***101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
***101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
***101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
***101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

* Management contract or compensatory agreement.

57

** 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.

58

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, 2010 to be signed on their behalf by the undersigned, thereunto duly authorized.

	PG&E CORPORATION		PACIFIC GAS AND ELECTRIC COMPANY
	(Registrant)		(Registrant)
	*PETER A. DARBEE		*CHRISTOPHER P. JOHNS
	Peter A. Darbee		Christopher P. Johns
By:	Chairman of the Board, Chief Executive Officer, and President	By:	President
Date:	February 17, 2011	Date:	February 17, 2011

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated.

Signature	Title	Date
A. Principal Executive Officers
*PETER A. DARBEE	Chairman of the Board, Chief Executive Officer, and President (PG&E Corporation)	February 17, 2011
Peter A. Darbee
*CHRISTOPHER P. JOHNS	President (Pacific Gas and Electric Company)	February 17, 2011
Christopher P. Johns
B. Principal Financial Officers
*KENT M. HARVEY	Senior Vice President, Chief Financial Officer, and Treasurer (PG&E Corporation)	February 17, 2011
Kent M. Harvey
*SARA A. CHERRY	Vice President, Finance and Chief Financial Officer (Pacific Gas and Electric Company)	February 17, 2011
Sara A. Cherry
C. Principal Accounting Officer
*DINYAR B. MISTRY	Vice President and Controller (PG&E Corporation and Pacific Gas and Electric Company)	February 17, 2011
Dinyar B. Mistry
D. Directors
*DAVID R. ANDREWS	Director	February 17, 2011
David R. Andrews
*LEWIS CHEW	Director	February 17, 2011
Lewis Chew

59

*C. LEE COX	Director	February 17, 2011
C. Lee Cox
*PETER A. DARBEE	Director	February 17, 2011
Peter A. Darbee
*MARYELLEN C. HERRINGER	Director	February 17, 2011
Maryellen C. Herringer
*CHRISTOPHER P. JOHNS	Director (Pacific Gas and Electric Company only)	February 17, 2011
Christopher P. Johns
*ROGER H. KIMMEL	Director	February 17, 2011
Roger H. Kimmel
*RICHARD A. MESERVE	Director	February 17, 2011
Richard A. Meserve
*FORREST E. MILLER	Director	February 17, 2011
Forrest E. Miller
*ROSENDO G. PARRA	Director	February 17, 2011
Rosendo G. Parra
*BARBARA L. RAMBO	Director	February 17, 2011
Barbara L. Rambo
*BARRY LAWSON WILLIAMS	Director	February 17, 2011
Barry Lawson Williams

*By:	HYUN PARK
	HYUN PARK, Attorney-in-Fact

60

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PG&E Corporation and Pacific Gas and Electric Company

San Francisco, California

We have audited the consolidated financial statements of PG&E Corporation and subsidiaries (the “Company”) and Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, and the Company’s and the Utility’s internal control over financial reporting as of December 31, 2010, and have issued our report thereon dated February 17, 2011; such consolidated financial statements and our report are included in your 2010 Annual Report to Shareholders of the Company and the Utility and are incorporated herein by reference. Our audits also included the consolidated financial statement schedules of the Company and Utility listed in Item 15(a)2. These consolidated financial statement schedules are the responsibility of the Company’s and the Utility’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

DELOITTE & TOUCHE LLP

February 17, 2011

San Francisco, California

61

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF INCOME

(in millions, except per share amounts)

	Year Ended December 31,
	2010			2009			2008
Administrative service revenue	$	53		$	59		$	119
Equity in earnings of subsidiaries		1,105			1,231			1,182
Operating expenses		(55	)		(61	)		(105	)
Interest income		1			1			4
Interest expense		(35	)		(43	)		(30	)
Other income (expense)		4			11			(46	)
Income before income taxes		1,073			1,198			1,124
Income tax benefit		26			22			60
Income from continuing operations		1,099			1,220			1,184
Gain on disposal of NEGT		—			—			154
Income Available for Common Shareholders	$	1,099		$	1,220		$	1,338
Weighted average common shares outstanding, basic		382			368			357
Weighted average common shares outstanding, diluted		392			386			358
Earnings per common share, basic	$	2.86		$	3.25		$	3.64
Earnings per common share, diluted	$	2.82		$	3.20		$	3.63

In calculating diluted EPS, PG&E Corporation applies the if-converted method to reflect the dilutive effect of the Convertible Subordinated Notes to the extent that the impact is dilutive when compared to basic EPS. In addition, PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS.

Accordingly, the basic and diluted earnings per share calculation for the ended December 31, 2008 reflects the allocation of earnings between PG&E Corporation common stock and the participating security.

62

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT — (Continued)

CONDENSED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2010			2009
ASSETS
Current Assets
Cash and cash equivalents	$	240		$	193
Advances to affiliates		25			20
Deferred income taxes		5			3
Income taxes receivable		1			9
Other current assets		—			5
Total current assets		271			230
Noncurrent Assets
Equipment		14			14
Accumulated depreciation		(14	)		(13	)
Net equipment		—			1
Investments in subsidiaries		11,618			10,935
Other investments		89			84
Deferred income taxes		116			32
Other		2			4
Total noncurrent assets		11,825			11,056
Total Assets	$	12,096		$	11,286
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable – related parties	$	106		$	32
Accounts payable – other		3			2
Long-term debt, classified as current		—			247
Income taxes payable		1			12
Other		213			199
Total current liabilities		323			492
Noncurrent Liabilities
Long-term debt		349			348
Income taxes payable		48			14
Other		94			99
Total noncurrent liabilities		491			461
Common Shareholders’ Equity
Common stock		6,878			6,280
Reinvested earnings		4,606			4,213
Accumulated other comprehensive loss		(202	)		(160	)
Total common shareholders’ equity		11,282			10,333
Total Liabilities and Shareholders’ Equity	$	12,096		$	11,286

63

PG&E CORPORATION

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2010			2009			2008
Cash Flows from Operating Activities:
Net income	$	1,099		$	1,220		$	1,338
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		38			20			27
Equity in earnings of subsidiaries		(1,105	)		(1,231	)		(1,180	)
Deferred income taxes and tax credits, net		19			—			—
Noncurrent income taxes receivable/payable		34			(9	)		(108	)
Current income taxes receivable/payable		(1	)		148			46
Other		(50	)		(13	)		(150	)
Net cash provided by (used in) operating activities		34			135			(27	)
Cash Flows From Investing Activities:
Investment in subsidiaries		(340	)		(721	)		(275	)
Dividends received from subsidiaries		716			624			596
Other		(4	)		10			(12	)
Net cash provided by (used in) investing activities		372			(87	)		309
Cash Flows From Financing Activities(1):
Proceeds from issuance of long-term debt, net of discount and issuance costs of $2 in 2009		—			348			—
Common stock issued		303			219			225
Common stock dividends paid		(662	)		(590	)		(546	)
Other		—			1			2
Net cash used in financing activities		(359	)		(22	)		(319	)
Net change in cash and cash equivalents		47			26			(37	)
Cash and cash equivalents at January 1		193			167			204
Cash and cash equivalents at December 31	$	240		$	193		$	167

(1) On January 15, 2010, PG&E Corporation paid a quarterly common stock dividend of $0.42 per share. On April 15, July 15, and October 15, 2010, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

On January 15, 2009, PG&E Corporation paid a quarterly common stock dividend of $0.39 per share. On April 15, July 15, and October 15, 2009, PG&E Corporation paid quarterly common stock dividends of $0.42 per share.

On January 15, 2008, PG&E Corporation paid a quarterly common stock dividend of $0.36 per share. On April 15, July 15, and October 15, 2008, PG&E Corporation paid quarterly common stock dividends of $0.39 per share. Of the total dividend payments made by PG&E Corporation in 2008, approximately $28 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.

64

PG&E Corporation

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2010, 2009, and 2008

(in millions)

			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions (3)		Balance at End of Period
Valuation and qualifying accounts deducted from assets:
2010:
Allowance for uncollectible accounts(1) (2)	$	68	$	56	$	—	$	43	$	81
2009:
Allowance for uncollectible accounts(1) (2)	$	76	$	68	$	—	$	76	$	68
2008:
Allowance for uncollectible accounts(1) (2)	$	58	$	68	$	11	$	61	$	76

⁽¹⁾ Allowance for uncollectible accounts is deducted from “Accounts receivable – Customers, net.”

⁽²⁾ Allowance for uncollectible accounts does not include NEGT.

⁽³⁾ Deductions consist principally of write-offs, net of collections of receivables previously written off.

65

Pacific Gas and Electric Company

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2010, 2009, and 2008

(in millions)

			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged  to Other Accounts		Deductions(2)		Balance at End of Period
Valuation and qualifying accounts deducted from assets:
2010:
Allowance for uncollectible accounts (1)	$	68	$	56	$	—	$	43	$	81
2009:
Allowance for uncollectible accounts (1)	$	76	$	68	$	—	$	76	$	68
2008:
Allowance for uncollectible accounts (1)	$	58	$	68	$	11	$	61	$	76

⁽¹⁾ Allowance for uncollectible accounts is deducted from “Accounts receivable – Customers, net.”

⁽²⁾ Deductions consist principally of write-offs, net of collections of receivables previously written off.

66

EXHIBIT INDEX

Exhibit     Number	Exhibit Description
2.1	Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company’s Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1)
2.2	Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company’s Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2)
3.1	Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
3.2	Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
3.3	Bylaws of PG&E Corporation amended as of September 16, 2009 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2009 (File No. 1-12609), Exhibit 3.1)
3.4	Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
3.5	Bylaws of Pacific Gas and Electric Company amended as of February 17, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2009 (File No. 1-2348), Exhibit 3.5)
4.1	Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
4.2	First Supplemental Indenture dated as of March 13, 2007 relating to the Utility’s issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
4.3	Second Supplemental Indenture dated as of December 4, 2007 relating to the Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (file No. 1-2348), Exhibit 4.1)
4.4	Third Supplemental Indenture dated as of March 3, 2008 relating to the Utility’s issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 3, 2008 (File No. 1-2348), Exhibit 4.1)

Exhibit     Number	Exhibit Description
4.5	Fourth Supplemental Indenture dated as of October 21, 2008 relating to the Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 21, 2008 (File No. 1-2348), Exhibit 4.1)
4.6	Fifth Supplemental Indenture dated as of November 18, 2008 relating to the Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25% Senior Notes due December 1, 2013 and $200 million principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2008 (File No. 1-2348), Exhibit 4.1)
4.7	Sixth Supplemental Indenture, dated as of March 6, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1)
4.8	Seventh Supplemental Indenture dated as of June 11, 2009 relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due June 10, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 11, 2009 (File No. 1-2348), Exhibit 4.1)
4.9	Eighth Supplemental Indenture dated as of November 18, 2009 relating to the issuance of $550,000,000 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 Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1)
4.10	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 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)
4.11	Tenth Supplemental Indenture dated as of September 15, 2010 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1)
4.12	Eleventh Supplemental Indenture dated as of October 12, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due October 11, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 12, 2010 (File No. 1-2348), Exhibit 4.1)
4.13	Twelfth Supplemental Indenture dated as of November 18, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 (File No. 1-2348), Exhibit 4.1)
4.14	Senior Note Indenture related to PG&E Corporation’s 5.75% Senior Notes due April 1, 2014, dated as of March 12, 2009, between PG&E Corporation and Deutsche Bank Trust Company Americas as Trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.1)
4.15	First Supplemental Indenture, dated as of March 12, 2009 relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 5.75% Senior Notes due April 1, 2014 (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.2)

Exhibit     Number	Exhibit Description
10.1	Credit Agreement dated June 8, 2010, among (1) Pacific Gas and Electric Company, as borrower, (2) Wells Fargo Bank, N.A., as administrative agent and a lender, (3) The Royal Bank of Scotland plc, as syndication agent and a lender, (4) Banco Bilbao Vizcaya Argentaria, S.A., New York Branch, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, and U.S. Bank, N.A., as documentation agents and lenders, and (5) the following other lenders: Bank of America, N.A., Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, New York Branch, Goldman Sachs Bank USA, Mizuho Corporate Bank (USA), Morgan Stanley Bank, N.A., Royal Bank of Canada, UBS Loan Finance LLC, Citibank, N.A., East West Bank, RBC Bank (USA), JPMorgan Chase Bank, N.A., and The Northern Trust Company. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2010 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.2	Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.3	Amendment and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman Brothers Bank, FSB has been removed as a lender under the Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007, filed as Exhibit 10.1 above (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.4	Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentation agents and lenders, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)
10.5	Amendment and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman Brothers Bank, FSB has been removed as a lender under the Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentation agents and lenders, and other lenders, dated February 26, 2007, filed as Exhibit 10.3 above (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)
10.6	Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99)
10.7	Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)

Exhibit     Number	Exhibit Description
10.8	Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9)
*10.9	PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)
*10.10	PG&E Corporation 2005 Supplemental Retirement Savings Plan effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009 and as further amended with respect to investment options effective as of July 13, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009) (File No. 1-12609), Exhibit 10.9
*10.11	Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)
*10.12	Amended and Restated Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.11)
*10.13	Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12)
*10.14	Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005) (File No. 1-12609), Exhibit 10.18)
*10.15	Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006) (File No. 1-12609), Exhibit 10.18)
*10.16	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and John S. Keenan dated November 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.21)
*10.17	Separation Agreement between Pacific Gas and Electric Company and Barbara Barcon effective March 4, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.1)
*10.18	Separation Agreement between PG&E Corporation and Nancy E. McFadden effective February 23, 2011
*10.19	PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.24)
*10.20	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2010 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.21)
*10.21	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2011

Exhibit     Number	Exhibit Description
*10.22	Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.27)
*10.23	Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.28)
*10.24	PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.1)
*10.25	Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.30)
*10.26	Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)
*10.27	Amendment to Postretirement Life Insurance Plan of the Pacific Gas and Electric Company dated December 30, 2008 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.32)
*10.28	PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)
*10.29	Resolution of the PG&E Corporation Board of Directors dated September 17, 2008, adopting director compensation arrangement effective January 1, 2009 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609 and File No. 12348), Exhibit 10.36)
*10.30	Resolution of the Pacific Gas and Electric Company Board of Directors dated September 17, 2008, adopting director compensation arrangement effective January 1, 2009 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609 and File No. 12348), Exhibit 10.37)
*10.31	Resolution of the PG&E Corporation Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011
*10.32	Resolution of the Pacific Gas and Electric Company Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011
*10.33	PG&E Corporation 2006 Long-Term Incentive Plan, as amended through December 15, 2010
*10.34	PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
*10.35	Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.39)

Exhibit     Number	Exhibit Description
*10.36	Form of Restricted Stock Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.5)
*10.37	Form of Amendment to Restricted Stock Agreements for grants made between January 2005 and March 2008 (amendments to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.45)
*10.38	Form of Restricted Stock Unit Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.2)
*10.39	Form of Performance Share Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.3)
*10.40	Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.2)
*10.41	Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.3)
*10.42	Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1)
*10.43	Form of Performance Share Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.44)
*10.44	Form of Performance Share Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.6)
*10.45	Form of Amended and Restated Performance Share Agreement for 2007 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.52)
*10.46	Form of Amended and Restated Performance Share Agreement for 2008 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.53)
*10.47	PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.2)
*10.48	PG&E Corporation 2010 Executive Stock Ownership Guidelines as adopted September 14, 2010, effective January 1, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.3)
*10.49	PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.48)

Exhibit     Number	Exhibit Description
*10.50	PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2009 (amended to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.56)
*10.51	PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011
*10.52	PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
*10.53	Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 (amendment to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58)
*10.54	PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)
*10.55	PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39)
*10.56	PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective as of February 17, 2010 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.54)
*10.57	Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
*10.58	Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)
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
13	The following portions of the 2010 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: “Selected Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” financial statements of PG&E Corporation entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders’ Equity,” “Notes to the Consolidated Financial Statements,” “Quarterly Consolidated Financial Data (Unaudited),” “Management’s Report on Internal Control Over Financial Reporting,” and “Report of Independent Registered Public Accounting Firm.”
21	Subsidiaries of the Registrant
23	Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1	Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2	Powers of Attorney

Exhibit     Number	Exhibit Description
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	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	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
***101.INS	XBRL Instance Document
***101.SCH	XBRL Taxonomy Extension Schema Document
***101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
***101.DEF	XBRL Taxonomy Extension Definition 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.

EX-10.18

Exhibit 10.18

THE TERMS AND CONDITIONS OF THIS AGREEMENT ARE PURSUANT TO THE PG&E COMPANY OFFICER SEVERANCE PLAN, ADOPTED BY THE NOMINATING, COMPENSATION, AND GOVERNANCE COMMITTEE OF PG&E COMPANY, AND ARE NOT SUBJECT TO NEGOTIATION.

SEPARATION AGREEMENT

This Separation Agreement (“Agreement”) is made and entered into by and between Nancy McFadden and Pacific Gas and Electric Company (the “Company” or “PG&E”) (collectively the “Parties”) and sets forth the terms and conditions of Ms. McFadden’s separation from employment with the Company. The “Effective Date” of this Agreement is defined in paragraph 18(a).

1.        Resignation. Effective the close of business on December 31, 2010 (for purposes of this Agreement, the “Date of Resignation”), Ms. McFadden will resign from her position as Senior Vice President and Special Advisor of Pacific Gas and Electric Company. Ms. McFadden shall have until February 13, 2011, to accept this Agreement by submitting a signed copy to the Company. Regardless of whether Ms. McFadden accepts this Agreement, on the Date of Resignation, she will be paid all salary or wages and vacation accrued, unpaid and owed to her as of that date, she will remain entitled to any other benefits to which she is otherwise entitled under the provisions of the Company’s plans and programs, and she will receive notice of the right to continue her existing health-insurance coverage pursuant to COBRA.

The benefits set forth in paragraph 2 below are conditioned upon Ms. McFadden’s acceptance of this Agreement.

2.        Separation benefits. Even though Ms. McFadden is not otherwise entitled to them, in consideration of her acceptance of this Agreement, the Company will provide to Ms. McFadden the following separation benefits:

a.        Severance payment. Under the terms of the PG&E Company Officer Severance Policy, Ms. McFadden’s severance payment amount is $1,040,400. (ONE MILLION FORTY THOUSAND FOUR HUNDRED DOLLARS). On the Effective Date of this Agreement as set forth in paragraph 18(a) below, the Company will make the severance payment, less applicable withholdings and deductions to Ms. McFadden.

b.        Stock. Upon the Date of Resignation, but conditioned on the occurrence of the Effective Date of this Agreement as set forth in paragraph 18(a) below, all unvested restricted stock grants, and performance share grants provided to Ms. McFadden under PG&E Company’s 2006 Long-Term Incentive Plan shall continue to vest, terminate, or be canceled as provided under the terms of their respective plans or program, as modified by the PG&E Company Officer Severance Policy in effect at the time this Agreement is signed by Ms. McFadden. The payment and withdrawal of Ms. McFadden’s restricted stock grants, restricted stock unit grants, and performance share grants shall be as provided under the terms of their respective plans or program, as modified by the PG&E Company Officer Severance Policy in effect at the time this Agreement is signed by Ms. McFadden.

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c.        Career transition services. For a maximum period of one year following the Date of Resignation, the Company will provide Ms. McFadden with executive career transition services from the firm of Torchiana, Mastrov & Sapiro, Inc., in accordance with the contract between the Company and Torchiana, Mastrov & Sapiro, Inc. Ms. McFadden’s entitlement to services under this Agreement will terminate when she becomes employed, either by another employer or through self-employment other than consulting with the Company. If Ms. McFadden becomes employed, she will promptly notify PG&E Company’s Human Resources Officer to enable the Company to end the provision of services to her by Torchiana, Mastrov & Sapiro, Inc.

d.        Payment of COBRA premiums. If Ms. McFadden elects and is otherwise eligible to continue her existing health-insurance coverage pursuant to COBRA, the Company will pay her monthly COBRA premiums for the eighteen-month period commencing the first full month after the Date of Resignation and until and unless Ms. McFadden becomes covered under the health-insurance plan of another employer or through self-employment. Ms. McFadden will promptly notify the PG&E Company’s Human Resources Officer if she becomes employed within that period.

3.        Defense and indemnification in third-party claims. The Company and/or its parent, affiliate, or subsidiary will provide Ms. McFadden with legal representation and indemnification protection in any legal proceeding in which she is a party or is threatened to be made a party by reason of the fact that she is or was an employee or officer of the Company and/or its parent, affiliate or subsidiary, in accordance with the terms of the resolution of the Board of Directors of PG&E Company dated December 18, 1996.

4.        Cooperation with legal proceedings. Ms. McFadden will, upon reasonable notice, furnish information and proper assistance to the Company and/or its parent, affiliate or subsidiary (including truthful testimony and document production) as may reasonably be required by them or any of them in connection with any legal, administrative or regulatory proceeding in which they or any of them is, or may become, a party, or in connection with any filing or similar obligation imposed by any taxing, administrative or regulatory authority having jurisdiction, provided, however, that the Company and/or its parent, affiliate or subsidiary will pay all reasonable expenses incurred by Ms. McFadden in complying with this paragraph.

5.        Release of claims and covenant not to sue.

a.        In consideration of the separation benefits and other benefits the Company is providing under this Agreement, Ms. McFadden, on behalf of herself and her representatives, agents, heirs and assigns, waives, releases, discharges and promises never to assert any and all claims, liabilities or obligations of every kind and nature, whether known or unknown, suspected or unsuspected that she ever had, now has or might have as of the Effective Date against the Company or its predecessors, parent, affiliates, subsidiaries, shareholders, owners, directors, officers, employees, agents, attorneys, successors, or assigns. These released claims include, without limitation, any claims arising from or related to Ms. McFadden’s employment with the Company, its parent or any of its affiliates and subsidiaries, and the termination of that employment. These released claims also specifically include, but are not limited, any claims

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arising under any federal, state and local statutory or common law, such as (as amended and as applicable) Title VII of the Civil Rights Act, the Age Discrimination in Employment Act, the Americans With Disabilities Act, the Employee Retirement Income Security Act, the California Fair Employment and Housing Act, the California Labor Code, any other federal, state or local law governing the terms and conditions of employment or the termination of employment, and the law of contract and tort; and any claim for attorneys’ fees.

b.        Ms. McFadden acknowledges that there may exist facts or claims in addition to or different from those which are now known or believed by her to exist. Nonetheless, this Agreement extends to all claims of every nature and kind whatsoever, whether known or unknown, suspected or unsuspected, past or present, and Ms. McFadden specifically waives all rights under Section 1542 of the California Civil Code which provides that:

A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT KNOW OR SUSPECT TO EXIST IN HIS OR HER FAVOR AT THE TIME OF EXECUTING THE RELEASE, WHICH IF KNOWN TO HIM OR HER MUST HAVE MATERIALLY AFFECTED HIS OR HER SETTLEMENT WITH THE DEBTOR.

c.        With respect to the claims released in the preceding paragraphs, Ms. McFadden will not initiate or maintain any legal or administrative action or proceeding of any kind against the Company or its predecessors, parent, affiliates, subsidiaries, shareholders, owners, directors, officers, employees, agents, attorneys, successors, or assigns, for the purpose of obtaining any personal relief, nor (except as otherwise required or permitted by law) assist or participate in any such proceedings, including any proceedings brought by any third parties.

6.        Re-employment. Ms. McFadden will not seek any future re-employment with the Company, its parent or any of its subsidiaries or affiliates. This paragraph will not, however, preclude Ms. McFadden from accepting an offer of future employment from the Company, its parent or any of its subsidiaries or affiliates.

7.        Non-disclosure.

a.        Ms. McFadden will not disclose, publicize, or circulate to anyone in whole or in part, any information concerning the existence, terms, and/or conditions of this Agreement without the express written consent of the PG&E Company’s Chief Legal Officer unless otherwise required or permitted by law. Notwithstanding the preceding sentence, Ms. McFadden may disclose the terms and conditions of this Agreement to her family members, and any attorneys or tax advisors, if any, to whom there is a bona fide need for disclosure in order for them to render professional services to him, provided that the person first agrees to keep the information confidential and not to make any disclosure of the terms and conditions of this Agreement unless otherwise required or permitted by law.

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b.        Ms. McFadden will not use, disclose, publicize, or circulate any confidential or proprietary information concerning the Company or its subsidiaries or affiliates, which has come to her attention during her employment with the Company, unless doing so is expressly authorized in writing by the PG&E Company’s Chief Legal Officer, or is otherwise required or permitted by law. Before making any legally-required or permitted disclosure, Ms. McFadden will give the Company notice at least ten (10) business days in advance.

8.        Non-Disparagement. Ms. McFadden agrees to refrain from performing any act, engaging in any conduct or course of action or making or publishing any statements, claims, allegations or assertions, which have or may reasonably have the effect of demeaning the name or business reputation of the Company, or any of its parent companies, subsidiaries or affiliates, or any of their respective employees, officers, directors, agents or advisors in their capacities as such or which adversely affects (or may reasonably be expected adversely to affect) the best interests (economic or otherwise) of any of them. The Company agrees to refrain from performing any act, engaging in any conduct or course of action or making or publishing any statements, claims, allegations or assertions in any print, electronic or television media or in investor conference calls or webcasts, which have or may reasonably have the effect of demeaning the name or business reputation of Ms. McFadden. The Company further agrees to instruct its officers, (in each case, while such person remains an officer of the Company) to comply with the Company’s obligations under this paragraph. In the event the Company’s Chief Legal Officer or Head of Human Resources acquires actual knowledge that a violation of the Company’s obligations under this paragraph 8 has occurred, the Company shall take reasonable action to reprimand and further discourage such behavior in violation of this paragraph 8. Each Party agrees that nothing in this paragraph 8 shall preclude the other Party from fulfilling any duty or obligation that she or it may have at law, from responding to any subpoena or official inquiry from any court or government agency, including providing truthful testimony, documents subpoenaed or requested or otherwise cooperating in good faith with any proceeding or investigation, or from taking any reasonable actions to enforce such party’s rights under this Agreement in accordance with the dispute resolution provisions specified in paragraph 15 hereof. Each Party shall continue to comply with its or her obligations under this Paragraph 8 regardless of any alleged breach by the other Party of its or her agreements contained in this paragraph 8 unless and until there has been a final determination by a court or an arbitration panel that the other Party has breached its or her obligations under this paragraph.

9.        No unfair competition.

a.        Ms. McFadden will not engage in any unfair competition against the Company, its parent or any of its subsidiaries or affiliates.

b.        For a period of one year after the Effective Date, Ms. McFadden will not, directly or indirectly, solicit or contact for the purpose of diverting or taking away or attempt to solicit or contact for the purpose of diverting or taking away:

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(1) any existing customer of the Company or its parent, affiliates or subsidiaries;

(2) any prospective customer of the Company or its parent, affiliates or subsidiaries about whom Ms. McFadden acquired information as a result of any solicitation efforts by the Company or its parent, affiliates or subsidiaries, or by the prospective customer, during Ms. McFadden’s employment with the Company;

(3) any existing vendor of the Company or its parent, affiliates or subsidiaries;

(4) any prospective vendor of the Company or its parent, affiliates or subsidiaries, about whom Ms. McFadden acquired information as a result of any solicitation efforts by the Company or its parent, affiliates or subsidiaries, or by the prospective vendor, during Ms. McFadden’s employment with the Company;

(5) any existing employee, agent or consultant of the Company or its parent, affiliates or subsidiaries, to terminate or otherwise alter the person’s or entity’s employment, agency or consultant relationship with the Company or its parent, affiliates or subsidiaries; or

(6) any existing employee, agent or consultant of the Company or its parent, affiliates or subsidiaries, to work in any capacity for or on behalf of any person, company or other business enterprise that is in competition with the Company or its parent, affiliates or subsidiaries.

10.        Material breach by Employee. In the event that Ms. McFadden breaches any material provision of this Agreement, including but not necessarily limited to paragraphs 4, 5, 6, 7, 8 and/or 9, the Company will have no further obligation to pay or provide to her any unpaid amounts or benefits specified in this Agreement and will be entitled to immediate return of any and all amounts or benefits previously paid or provided to her under this Agreement and to recalculate any future pension benefit entitlement without the additional credited age she received or would have received under this Agreement. Despite any breach by Ms. McFadden, her other duties and obligations under this Agreement, including her waivers and releases, will remain in full force and effect. In the event of a breach or threatened breach by Ms. McFadden of any of the provisions in paragraphs 4, 5, 6, 7, 8, and/or 9, the Company will, in addition to any other remedies provided in this Agreement, be entitled to equitable and/or injunctive relief and,

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because the damages for such a breach or threatened breach will be difficult to determine and will not provide a full and adequate remedy, the Company will also be entitled to specific performance by Ms. McFadden of her obligations under paragraphs 4, 5, 6, 7, 8, and/or 9. Pursuant to paragraph 15, and except as otherwise prohibited or limited by law, Ms. McFadden will also be liable for any litigation costs and expenses that the Company incurs in successfully seeking enforcement of its rights under this Agreement, including reasonable attorney’s fees.

11.        Material breach by the Company. Ms. McFadden will be entitled to recover actual damages in the event of any material breach of this Agreement by the Company, including any unexcused late or non-payment of any amounts owed under this Agreement, or any unexcused failure to provide any other benefits specified in this Agreement. In the event of a breach or threatened breach by the Company of any of its material obligations to him under this Agreement, Ms. McFadden will be entitled to seek, in addition to any other remedies provided in this Agreement, specific performance of the Company’s obligations and any other applicable equitable or injunctive relief. Pursuant to paragraph 15, and except as prohibited or limited by law, the Company will also be liable for any litigation costs and expenses that Ms. McFadden incurs in successfully seeking enforcement of her rights under this Agreement, including reasonable attorney’s fees. Despite any breach by the Company, its other duties and obligations under this Agreement will remain in full force and effect.

12.        No admission of liability. This Agreement is not, and will not be considered, an admission of liability or of a violation of any applicable contract, law, rule, regulation, or order of any kind.

13.        Complete agreement. This Agreement sets forth the entire agreement between the Parties pertaining to the subject matter of this Agreement and fully supersedes any prior or contemporaneous negotiations, representations, agreements, or understandings between the Parties with respect to any such matters, whether written or oral (including any that would have provided Ms. McFadden with any different severance arrangements). The Parties acknowledge that they have not relied on any promise, representation or warranty, express or implied, not contained in this Agreement. Parole evidence will be inadmissible to show agreement by and among the Parties to any term or condition contrary to or in addition to the terms and conditions contained in this Agreement.

14.        Severability. If any provision of this Agreement is determined to be invalid, void, or unenforceable, the remaining provisions will remain in full force and effect except that, should paragraphs 4, 5, 6, 7, 8 and/or 9 be held invalid, void or unenforceable, either jointly or separately, the Company will be entitled to rescind the Agreement and/or recover from Ms. McFadden any payments made and benefits provided to her under this Agreement.

15.        Arbitration. With the exception of any request for specific performance, injunctive or other equitable relief, any dispute or controversy of any kind arising out of or related to this Agreement, Ms. McFadden’s employment with the Company (or with the employing subsidiary), the separation of Ms. McFadden from that employment and from her positions as an officer and/or director of the Company or any subsidiary or affiliate, or any claims

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for benefits, will be resolved exclusively by final and binding arbitration using a three-member arbitration panel in accordance with the Commercial Arbitration Rules of the American Arbitration Association currently in effect, provided, however, that in rendering their award, the arbitrators will be limited to accepting the position of Ms. McFadden or the Company. The only claims not covered by this paragraph are any non-waivable claims for benefits under workers’ compensation or unemployment insurance laws, which will be resolved under those laws. Any arbitration pursuant to this paragraph will take place in San Francisco, California. The Parties may be represented by legal counsel at the arbitration but must bear their own fees for such representation in the first instance. The prevailing party in any dispute or controversy covered by this paragraph, or with respect to any request for specific performance, injunctive or other equitable relief, will be entitled to recover, in addition to any other available remedies specified in this Agreement, all litigation expenses and costs, including any arbitrator, administrative or filing fees and reasonable attorneys’ fees, except as prohibited or limited by law. The Parties specifically waive any right to a jury trial on any dispute or controversy covered by this paragraph. Judgment may be entered on the arbitrators’ award in any court of competent jurisdiction. Subject to the arbitration provisions of this paragraph, the sole jurisdiction and venue for any action related to the subject matter of this Agreement will be the California state and federal courts having within their jurisdiction the location of the Company’s principal place of business in California at the time of such action, and both Parties thereby consent to the jurisdiction of such courts for any such action.

16.        Governing law. This Agreement will be governed by and construed under the laws of the United States and, to the extent not preempted by such laws, by the laws of the State of California, without regard to their conflicts of laws provisions.

17.        No waiver. The failure of either Party to exercise or enforce, at any time, or for any period of time, any of the provisions of this Agreement will not be construed as a waiver of that provision, or any portion of that provision, and will in no way affect that party’s right to exercise or enforce such provisions. No waiver or default of any provision of this Agreement will be deemed to be a waiver of any succeeding breach of the same or any other provisions of this Agreement.

18.        Acceptance of Agreement.

a.        Ms. McFadden was provided over 21 days to consider and accept the terms of this Agreement and was advised to consult with an attorney about the Agreement before signing it. The provisions of the Agreement are, however, not subject to negotiation. After signing the Agreement, Ms. McFadden will have an additional seven (7) days in which to revoke in writing acceptance of this Agreement. To revoke, Ms. McFadden will submit a signed statement to that effect to PG&E Company’s Chief Legal Officer before the close of business on the seventh day. If Ms. McFadden does not submit a timely revocation, the Effective Date of this Agreement will be February 23.

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b.        Ms. McFadden acknowledges reading and understanding the contents of this Agreement, being afforded the opportunity to review carefully this Agreement with an attorney of her choice, not relying on any oral or written representation not contained in this Agreement, signing this Agreement knowingly and voluntarily, and, after the Effective Date of this Agreement, being bound by all of its provisions.

Dated: __________________.	PACIFIC GAS AND ELECTRIC COMPANY
	By:
Dated: __________________.	NANCY MCFADDEN

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EX-10.21

Exhibit 10.21

2011 OFFICER SHORT-TERM INCENTIVE PLAN

On February 15, 2011, the Compensation Committee of the PG&E Corporation Board of Directors (“Committee”) approved the specific performance targets for each component of the 2011 Short-Term Incentive Plan (“STIP”). The Committee previously approved the STIP structure and the weighting of each component in December 2010. Officers of PG&E Corporation and Pacific Gas and Electric Company (“Utility”) (together, the “Companies”) are eligible to receive cash incentives under the STIP based on the extent to which the adopted 2011 performance targets are met. Target cash awards under the STIP may range from 40 percent to 100 percent of base salary depending on officer level, with a maximum payout of 200 percent of the officer’s targeted award, as determined by the Committee. The Committee will retain complete discretion to determine and make final STIP awards to all officers and non-officer employees.

The corporate financial performance target, with a weighting of 50%, is based on PG&E Corporation’s budgeted earnings from operations that were previously approved by the Board of Directors, consistent with the basis for reporting and guidance to the financial community. As with previous earnings performance scales, unbudgeted items impacting comparability such as changes in accounting methods, workforce restructuring, and one-time occurrences will be excluded.

The Committee also approved the 2011 performance targets for each of the four other measures set forth in the table below. The 2010 performance results for each of these measures are included for comparative purposes.

2011 STIP Operational Performance Targets⁽¹⁾

Measure	Relative Weight	2010 Results	2011 Target
Operational Excellence Index(2) (Previously Reliable Energy Delivery Index & Safety Index)	25.0%	0.902 (REDI) 1.000 (Safety)		1.000
Customer Satisfaction and Brand Health Index (Residential & Business)(3)	15.0%	74.60		75.30
Employee Engagement Index (Premier) Survey(4)	5%	67.59		69.59
Environmental Leadership(5)	5%	1.842		1.000

1. As explained above, 50% of the STIP award will be based on achievement of corporate earnings from operations targets.

2. The Operational Excellence Index is a new measure that combines two previously separate measures: the Reliable Energy Delivery Index (REDI) and the Safety Index. This new measure is comprised of three subcomponents: (1) Electric Reliable Energy Delivery, which measures the Utility’s reliable energy delivery with respect to electricity, (2) Gas Reliable Energy Delivery, which measures the Utility’s reliable energy delivery with respect to gas, and (3) Safety Performance, which measures performance on employee safety and reinforces the Companies’ commitment to employees and the importance of safety to the Companies’ performance. The Safety Performance subcomponent includes the same two metrics used in the 2010 STIP: (1) Occupational Safety and Health Administration (OSHA) Recordable Rate, and (2) Motor Vehicle Incident (MVI) Rate. The Committee will retain complete discretion to reduce the final Safety Performance rating downward to zero based on the Companies’ overall safety performance for 2011. The Companies’ overall safety performance will be measured both by the quantitative measures described above and by qualitative performance. With respect to qualitative performance, the Committee will consider the collective impact that the Companies’ business operations have had on public and employee safety.

3. The Customer Satisfaction and Brand Health Index measures Utility customer perceptions of the Utility’s performance in delivering services, such as reliability, pricing of services, customer service experience, and favorability toward the Pacific Gas and Electric Company brand. The score on this measure is the result of a quarterly survey performed by an independent research firm, BlueOcean Market Intelligence, and is a combination of (1) a customer satisfaction score, which has a 75% weighting, and (2) a brand favorability score (measuring the relative strength of the Pacific Gas and Electric Company brand against a select group of companies), which has a 25% weighting. The customer satisfaction score will measure overall satisfaction with the Utility’s operational performance in delivering its services. The brand favorability score will measure residential, small business. and medium business customer perceptions.

4. The Employee Engagement Index is based on eight questions from the Premier Survey that were developed by the Companies’ survey vendor, Valtera Corporation. These eight questions are part of Valtera Corporation’s national survey that includes more than 180 companies on Fortune’s “Best Companies to Work For” and “Most Admired Companies” lists. The Premier Survey is the primary tool used to measure employee engagement at PG&E Corporation and the Utility.

5. Environmental compliance is measured by the (1) number of Notices of Violation (NOV) received, and (2) the Utility’s operational footprint in reducing energy and water usage, and increasing administrative waste diversion from landfill. Energy reduction is measured by the percent reduction in millions of British thermal units for a subset of Utility facilities. Water use reduction is measured by the percentage reduction in water consumption, in gallons, for a subset of Utility facilities. Administrative waste diversion is measured by the percentage reduction in administrative waste disposal at a subset of Utility facilities. Administrative waste includes non-hazardous waste, such as glass, paper, and certain metals produced by buildings. The focus of this measure is to divert waste from landfills, primarily through increased recycling efforts. Reductions are cumulative each year. Targets represent additional reductions over those achieved in 2010.

EX-10.31

Exhibit 10.31

Director Compensation

RESOLUTION OF THE

BOARD OF DIRECTORS OF

PG&E CORPORATION

December 15, 2010

BE IT RESOLVED that, effective January 1,2011, advisory directors and directors who are not employees of this corporation or Pacific Gas and Electric Company (collectively, “non-employee directors”) shall be paid a retainer of $13,750 per calendar quarter, which shall be in addition to fees paid for attendance at Board meetings, Board committee meetings, and shareholder meetings; and

BE IT FURTHER RESOLVED that, effective January 1, 2011, the non-employee director who serves as lead director shall be paid an additional retainer of $12,500 per calendar quarter; and

BE IT FURTHER RESOLVED that, effective January 1, 2011, the non-employee director who is duly appointed to chair the Audit Committee of this Board shall be paid an additional retainer of $12,500 per calendar quarter, and the non-employee directors who are duly appointed to chair the other permanent committees of this Board shall be paid an additional retainer of $2,500 per calendar quarter; and

BE IT FURTHER RESOLVED that, effective January 1, 2011, each non-employee director shall be paid a fee of $1,750 for each meeting of the Board and each meeting of a Board committee (of which such non-employee director is a member) attended; provided, however, that each non-employee director who is a member of the Audit Committee shall be paid a fee of $2,750 for each meeting of the Audit Committee attended; and

BE IT FURTHER RESOLVED that, effective January 1, 2011, non-employee directors attending any meeting of this corporation’s shareholders that is not held on the same day as a meeting of this Board shall be paid a fee of $1,750 for each such meeting attended; and

BE IT FURTHER RESOLVED that non-employee directors shall be eligible to participate in the PG&E Corporation 2006 Long-Term Incentive Plan under the terms and conditions of that Plan, as adopted by this Board and as may be amended from time to time; and

BE IT FURTHER RESOLVED that members of this Board shall be reimbursed for reasonable expenses incurred in connection with attending Board, Board committee, or shareholder meetings, or participating in other activities undertaken on behalf of this corporation; and

BE IT FURTHER RESOLVED that, effective January 1, 2011, the resolution on this subject adopted by the Board of Directors on September 17, 2008 is hereby superseded.

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EX-10.32

Exhibit 10.32

Director Compensation

RESOLUTION OF THE

BOARD OF DIRECTORS OF

PACIFIC GAS AND ELECTRIC COMPANY

December 15, 2010

BE IT RESOLVED that, effective January 1, 2011, advisory directors and directors who are not employees of this company or PG&E Corporation (collectively, “non-employee directors”) shall be paid a retainer of $13,750 per calendar quarter, which shall be in addition to any fees paid for attendance at Board meetings, Board committee meetings, and shareholder meetings; provided, however, that a non-employee director shall not be paid a retainer by this company for any calendar quarter during which such director also serves as a non-employee director of PG&E Corporation; and

BE IT FURTHER RESOLVED that, effective January 1, 2011, the non-employee director who serves as lead director shall be paid an additional retainer of $12,500 per calendar quarter; provided, however, that a non-employee director who serves as lead director shall not be paid an additional retainer by this company for any calendar quarter during which such director also serves as lead director of the PG&E Corporation Board of Directors; and

BE IT FURTHER RESOLVED that, effective January 1, 2011, the non-employee director who is duly appointed to chair the Audit Committee of this Board shall be paid an additional retainer of $12,500 per calendar quarter, and the non-employee directors who are duly appointed to chair the other permanent committees of this Board shall be paid an additional retainer of $2,500 per calendar quarter; provided, however, that a non-employee director duly appointed to chair a permanent committee of this Board shall not be paid an additional retainer by this company for any calendar quarter during which such director also serves as chair of the corresponding committee of the PG&E Corporation Board of Directors; and

BE IT FURTHER RESOLVED that, effective January 1, 2011, each non-employee director attending any meeting of the Board that is not held concurrently or sequentially with a meeting of the Board of Directors of PG&E Corporation, or any meeting of a Board committee (of which such non-employee director is a member) that is not held concurrently or sequentially with a meeting of the corresponding committee of the PG&E

Corporation Board, shall be paid a fee of $1,750 for each such Board or Board committee meeting attended; provided, however, that each non-employee director who is a member of the Audit Committee of this Board attending any meeting of such Audit Committee that is not held concurrently or sequentially with a meeting of the Audit Committee of the PG&E Corporation Board shall be paid a fee of $2,750 for each such meeting attended; and

BE IT FURTHER RESOLVED that, effective January 1, 2011, non-employee directors attending any meeting of this company’s shareholders that (1) is not held on the same day as a meeting of this Board or a meeting of the Board of Directors of PG&E Corporation, and (2) is not held concurrently or sequentially with a meeting of the shareholders of PG&E Corporation shall be paid a fee of $1,750 for each such meeting attended; and

BE IT FURTHER RESOLVED that members of this Board shall be reimbursed for reasonable expenses incurred in connection with attending Board, Board committee, or shareholder meetings, or participating in other activities undertaken on behalf of this company; and

BE IT FURTHER RESOLVED that, effective January 1, 2011, the resolution on this subject adopted by the Board of Directors on September 17, 2008 is hereby superseded.

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EX-10.33

Exhibit 10.33

PG&E Corporation

2006 Long-Term Incentive Plan

TABLE OF CONTENTS

			Page
1.	Establishment, Purpose and Term of Plan			1
	1.1	Establishment		1
	1.2	Purpose		1
	1.3	Term of Plan		1
2.	Definitions and Construction			1
	2.1	Definitions		1
	2.2	Construction		7
3.	Administration			7
	3.1	Administration by the Committee		7
	3.2	Authority of Officers		8
	3.3	Administration with Respect to Insiders		8
	3.4	Committee Complying with Section 162(m)		8
	3.5	Powers of the Committee		8
	3.6	Option or SAR Repricing		9
	3.7	Indemnification		10
4.	Shares Subject to Plan			10
	4.1	Maximum Number of Shares Issuable		10
	4.2	Adjustments for Changes in Capital Structure		10
5.	Eligibility and Award Limitations			11
	5.1	Persons Eligible for Awards		11
	5.2	Participation		11
	5.3	Incentive Stock Option Limitations		11
	5.4	Award Limits		12
6.	Terms and Conditions of Options			13
	6.1	Exercise Price		13
	6.2	Exercisability and Term of Options		13
	6.3	Payment of Exercise Price		14
	6.4	Effect of Termination of Service		14
	6.5	Transferability of Options		15
7.	Terms and Conditions of Nonemployee Director Awards			15
	7.1	Grant of Restricted Stock Unit		15
	7.2	Effect of Termination of Service as a Nonemployee Director		16
	7.3	Effect of Change in Control on Nonemployee Director Awards		17

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TABLE OF CONTENTS

(Continued)

			Page
8.	Terms and Conditions of Stock Appreciation Rights			17
	8.1	Types of SARs Authorized		17
	8.2	Exercise Price		17
	8.3	Exercisability and Term of SARs		17
	8.4	Deemed Exercise of SARs		17
	8.5	Effect of Termination of Service		17
	8.6	Nontransferability of SARs		18
9.	Terms and Conditions of Restricted Stock Awards			18
	9.1	Types of Restricted Stock Awards Authorized		18
	9.2	Purchase Price		18
	9.3	Purchase Period		18
	9.4	Vesting and Restrictions on Transfer		18
	9.5	Voting Rights, Dividends and Distributions		19
	9.6	Effect of Termination of Service		19
	9.7	Nontransferability of Restricted Stock Award Rights		19
10.	Terms and Conditions of Performance Awards			19
	10.1	Types of Performance Awards Authorized		19
	10.2	Initial Value of Performance Shares and Performance Units		20
	10.3	Establishment of Performance Period, Performance Goals and Performance Award Formula		20
	10.4	Measurement of Performance Goals		20
	10.5	Settlement of Performance Awards		21
	10.6	Voting Rights, Dividend Equivalent Rights and Distributions		21
	10.7	Effect of Termination of Service		22
	10.8	Nontransferability of Performance Awards		22
11.	Terms and Conditions of Restricted Stock Unit Awards			23
	11.1	Grant of Restricted Stock Unit Awards		23
	11.2	Vesting		23
	11.3	Voting Rights, Dividend Equivalent Rights and Distributions		23
	11.4	Effect of Termination of Service		24
	11.5	Settlement of Restricted Stock Unit Awards		24
	11.6	Nontransferability of Restricted Stock Unit Awards		24
12.	Deferred Compensation Awards			24
	12.1	Establishment of Deferred Compensation Award Programs		24
	12.2	Terms and Conditions of Deferred Compensation Awards		25
13.	Other Stock-Based Awards			26

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TABLE OF CONTENTS

(Continued)

			Page
14.	Change in Control			26
	14.1	Effect of Change in Control on Options and SARs		26
	14.2	Effect of Change in Control on Restricted Stock and Other Awards		26
	14.3	Nonemployee Director Awards		26
15.	Compliance with Securities Law			27
16.	Tax Withholding			27
	16.1	Tax Withholding in General		27
	16.2	Withholding in Shares		27
17.	Amendment or Termination of Plan			27
18.	Miscellaneous Provisions			28
	18.1	Repurchase Rights		28
	18.2	Provision of Information		28
	18.3	Rights as Employee, Consultant or Director		28
	18.4	Rights as a Shareholder		28
	18.5	Fractional Shares		28
	18.6	Severability		28
	18.7	Beneficiary Designation		29
	18.8	Unfunded Obligation		29
	18.9	Choice of Law		29
	18.10	Section 409A of the Code		29

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PG&E Corporation

2006 Long-Term Incentive Plan

(As adopted effective January 1, 2006, and

as amended effective on February 15, 2006, December 20, 2006, October 17, 2007, September 17, 2008, January 1, 2009, February 18, 2009, December 16, 2009, May 12, 2010, and December 15, 2010)

1. ESTABLISHMENT, PURPOSE AND TERM OF PLAN.

1.1 Establishment. The PG&E Corporation 2006 Long-Term Incentive Plan (the “Plan”) is hereby established effective as of January 1, 2006 (the “Effective Date”), provided it has been approved by the shareholders of the Company.

1.2 Purpose. The purpose of the Plan is to advance the interests of the Participating Company Group and its shareholders by providing an incentive to attract and retain the best qualified personnel to perform services for the Participating Company Group, by motivating such persons to contribute to the growth and profitability of the Participating Company Group, by aligning their interests with interests of the Company’s shareholders, and by rewarding such persons for their services by tying a significant portion of their total compensation package to the success of the Company. The Plan seeks to achieve this purpose by providing for Awards in the form of Options, Stock Appreciation Rights, Restricted Stock Awards, Performance Shares, Performance Units, Restricted Stock Units, Deferred Compensation Awards and other Stock-Based Awards as described below.

1.3 Term of Plan. The Plan shall continue in effect until the earlier of its termination by the Board or the date on which all of the shares of Stock available for issuance under the Plan have been issued and all restrictions on such shares under the terms of the Plan and the agreements evidencing Awards granted under the Plan have lapsed. However, all Awards shall be granted, if at all, within ten (10) years from the Effective Date. Moreover, Incentive Stock Options shall not be granted later than ten (10) years from the date of shareholder approval of the Plan.

2. DEFINITIONS AND CONSTRUCTION.

2.1 Definitions. Whenever used herein, the following terms shall have their respective meanings set forth below:

(a) “Affiliate” means (i) an entity, other than a Parent Corporation, that directly, or indirectly through one or more intermediary entities, controls the Company or (ii) an entity, other than a Subsidiary Corporation, that is controlled by the Company directly, or indirectly through one or more intermediary entities. For this purpose, the term “control” (including the term “controlled by”) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of the relevant entity, whether through the ownership of voting securities, by contract or otherwise; or shall have such other meaning assigned such term for the purposes of registration on Form S-8 under the Securities Act.

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(b) “Award” means any Option, SAR, Restricted Stock Award, Performance Share, Performance Unit, Restricted Stock Unit or Deferred Compensation Award or other Stock-Based Award granted under the Plan.

(c) “Award Agreement” means a written agreement between the Company and a Participant setting forth the terms, conditions and restrictions of the Award granted to the Participant.

(d) “Board” means the Board of Directors of the Company.

(e) “Change in Control” means, unless otherwise defined by the Participant’s Award Agreement or contract of employment or service, the occurrence of any of the following:

(i) any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act, but excluding any benefit plan for Employees or any trustee, agent or other fiduciary for any such plan acting in such person’s capacity as such fiduciary), directly or indirectly, becomes the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Exchange Act), of stock of the Company representing twenty percent (20%) or more of the combined voting power of the Company’s then outstanding voting stock; or

(ii) during any two consecutive years, individuals who at the beginning of such period constitute the Board cease for any reason to constitute at least a majority of the Board, unless the election, or the nomination for election by the shareholders of the Company, of each new Director was approved by a vote of at least two-thirds (2/3) of the Directors then still in office who were Directors at the beginning of the period; or

(iii) the consummation of any consolidation or merger of the Company other than a merger or consolidation which would result in the voting stock of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting stock of the surviving entity or any parent of such surviving entity) at least seventy percent (70%) of the Combined Voting Power of the Company, such surviving entity or the parent of such surviving entity outstanding immediately after the merger or consolidation; or

(iv) the approval of the Shareholders of the Company of any (1) sale, lease, exchange or other transfer (in one or a series of related transactions) of all or substantially all of the assets of the Company, or (2) any plan or proposal for the liquidation or dissolution of the Company.

For purposes of paragraph (iii), the term “Combined Voting Power” shall mean the combined voting power of the Company’s or other relevant entity’s then outstanding voting stock.

(f) “Code” means the Internal Revenue Code of 1986, as amended, and any applicable regulations promulgated thereunder.

(g) “Committee” means the Compensation Committee or other committee of the Board duly appointed to administer the Plan and having such powers as shall be specified by

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the Board. If no committee of the Board has been appointed to administer the Plan, the Board shall exercise all of the powers of the Committee granted herein, and, in any event, the Board may in its discretion exercise any or all of such powers.

(h) “Company” means PG&E Corporation, a California corporation, or any successor corporation thereto.

(i) “Consultant” means a person engaged to provide consulting or advisory services (other than as an Employee or a member of the Board) to a Participating Company, provided that the identity of such person, the nature of such services or the entity to which such services are provided would not preclude the Company from offering or selling securities to such person pursuant to the Plan in reliance on registration on a Form S-8 Registration Statement under the Securities Act.

(j) “Deferred Compensation Award” means an award of Stock Units granted to a Participant pursuant to Section 12 of the Plan.

(k) “Director” means a member of the Board.

(l) “Disability” means the permanent and total disability of the Participant, within the meaning of Section 22(e)(3) of the Code, except as otherwise set forth in the Plan or an Award Agreement.

(m) “Dividend Equivalent” means a credit, made at the discretion of the Committee or as otherwise provided by the Plan, to the account of a Participant in an amount equal to the cash dividends paid on one share of Stock for each share of Stock represented by an Award held by such Participant.

(n) “Employee” means any person treated as an employee (including an Officer or a member of the Board who is also treated as an employee) in the records of a Participating Company and, with respect to any Incentive Stock Option granted to such person, who is an employee for purposes of Section 422 of the Code; provided, however, that neither service as a member of the Board nor payment of a director’s fee shall be sufficient to constitute employment for purposes of the Plan. The Company shall determine in good faith and in the exercise of its discretion whether an individual has become or has ceased to be an Employee and the effective date of such individual’s employment or termination of employment, as the case may be. For purposes of an individual’s rights, if any, under the Plan as of the time of the Company’s determination, all such determinations by the Company shall be final, binding and conclusive, notwithstanding that the Company or any court of law or governmental agency subsequently makes a contrary determination.

(o) “Exchange Act” means the Securities Exchange Act of 1934, as amended.

(p) “Fair Market Value” means, as of any date, the value of a share of Stock or other property as determined by the Committee, in its discretion, or by the Company, in its discretion, if such determination is expressly allocated to the Company herein, subject to the following:

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(i) Except as otherwise determined by the Committee, if, on such date, the Stock is listed on a national or regional securities exchange or market system, the Fair Market Value of a share of Stock shall be the closing price of a share of Stock as quoted on the New York Stock Exchange or such other national or regional securities exchange or market system constituting the primary market for the Stock, as reported in The Wall Street Journal or such other source as the Company deems reliable. If the relevant date does not fall on a day on which the Stock has traded on such securities exchange or market system, the date on which the Fair Market Value shall be established shall be the last day on which the Stock was so traded prior to the relevant date, or such other appropriate day as shall be determined by the Committee, in its discretion.

(ii) Notwithstanding the foregoing, the Committee may, in its discretion, determine the Fair Market Value on the basis of the opening, closing, high, low or average sale price of a share of Stock or the actual sale price of a share of Stock received by a Participant, on such date, the preceding trading day, the next succeeding trading day or an average determined over a period of trading days. The Committee may vary its method of determination of the Fair Market Value as provided in this Section for different purposes under the Plan.

(iii) If, on such date, the Stock is not listed on a national or regional securities exchange or market system, the Fair Market Value of a share of Stock shall be as determined by the Committee in good faith without regard to any restriction other than a restriction which, by its terms, will never lapse.

(q) “Incentive Stock Option” means an Option intended to be (as set forth in the Award Agreement) and which qualifies as an incentive stock option within the meaning of Section 422(b) of the Code.

(r) “Insider” means an Officer, a Director or any other person whose transactions in Stock are subject to Section 16 of the Exchange Act.

(s) “Net-Exercise” means a procedure by which the Participant will be issued a number of shares of Stock determined in accordance with the following formula:

X = Y(A-B)/A, where

X = the number of shares of Stock to be issued to the Participant upon exercise of the Option;

Y = the total number of shares with respect to which the Participant has elected to exercise the Option;

A = the Fair Market Value of one (1) share of Stock;

B = the exercise price per share (as defined in the Participant’s Award Agreement).

(t) “Nonemployee Director” means a Director who is not an Employee.

(u) “Nonemployee Director Award” means an Award granted to a Nonemployee Director pursuant to Section 7 of the Plan.

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(v) “Nonstatutory Stock Option” means an Option not intended to be (as set forth in the Award Agreement) an incentive stock option within the meaning of Section 422(b) of the Code.

(w) “Officer” means any person designated by the Board as an officer of the Company.

(x) “Option” means the right to purchase Stock at a stated price for a specified period of time granted to a Participant pursuant to Section 6 or Section 7 of the Plan. An Option may be either an Incentive Stock Option or a Nonstatutory Stock Option.

(y) “Option Expiration Date” means the date of expiration of the Option’s term as set forth in the Award Agreement.

(z) “Parent Corporation” means any present or future “parent corporation” of the Company, as defined in Section 424(e) of the Code.

(aa) “Participant” means any eligible person who has been granted one or more Awards.

(bb) “Participating Company” means the Company or any Parent Corporation, Subsidiary Corporation or Affiliate.

(cc) “Participating Company Group” means, at any point in time, all entities collectively which are then Participating Companies.

(dd) “Performance Award” means an Award of Performance Shares or Performance Units.

(ee) “Performance Award Formula” means, for any Performance Award, a formula or table established by the Committee pursuant to Section 10.3 of the Plan which provides the basis for computing the value of a Performance Award at one or more threshold levels of attainment of the applicable Performance Goal(s) measured as of the end of the applicable Performance Period.

(ff) “Performance Goal” means a performance goal established by the Committee pursuant to Section 10.3 of the Plan.

(gg) “Performance Period” means a period established by the Committee pursuant to Section 10.3 of the Plan at the end of which one or more Performance Goals are to be measured.

(hh) “Performance Share” means a bookkeeping entry representing a right granted to a Participant pursuant to Section 10 of the Plan to receive a payment equal to the value of a Performance Share, as determined by the Committee, based on performance.

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(ii) “Performance Unit” means a bookkeeping entry representing a right granted to a Participant pursuant to Section 10 of the Plan to receive a payment equal to the value of a Performance Unit, as determined by the Committee, based upon performance.

(jj) “Restricted Stock Award” means an Award of Restricted Stock.

(kk) “Restricted Stock Unit” or “Stock Unit” means a bookkeeping entry representing a right granted to a Participant pursuant to Section 11 or Section 12 of the Plan, respectively, to receive a share of Stock on a date determined in accordance with the provisions of Section 11 or Section 12, as applicable, and the Participant’s Award Agreement.

(ll) “Restriction Period” means the period established in accordance with Section 9.4 of the Plan during which shares subject to a Restricted Stock Award are subject to Vesting Conditions.

(mm) “Retirement” means termination as an Employee of a Participating Company at age 55 or older, provided that the Participant was an Employee for at least five consecutive years prior to the date of such termination.

(nn) “Rule 16b-3” means Rule 16b-3 under the Exchange Act, as amended from time to time, or any successor rule or regulation.

(oo) “SAR” or “Stock Appreciation Right” means a bookkeeping entry representing, for each share of Stock subject to such SAR, a right granted to a Participant pursuant to Section 8 of the Plan to receive payment in any combination of shares of Stock or cash of an amount equal to the excess, if any, of the Fair Market Value of a share of Stock on the date of exercise of the SAR over the exercise price.

(pp) “Section 162(m)” means Section 162(m) of the Code.

(qq) “Section 409A Change in Control” means a “change in the ownership or effective control of the corporation, or in the ownership of a substantial portion of the assets of the corporation,” within the meaning of Section 409A of the Code, as such definition applies to the Company.

(rr) “Securities Act” means the Securities Act of 1933, as amended.

(ss) “Separation from Service” means a Participant’s “separation from service,” within the meaning of Section 409A of the Internal Revenue Code.

(tt) “Service” means a Participant’s employment or service with the Participating Company Group, whether in the capacity of an Employee, a Director or a Consultant. A Participant’s Service shall not be deemed to have terminated merely because of a change in the capacity in which the Participant renders such Service or a change in the Participating Company for which the Participant renders such Service, provided that there is no interruption or termination of the Participant’s Service. Furthermore, a Participant’s Service shall not be deemed to have terminated if the Participant takes any military leave, sick leave, or other bona fide leave of absence approved by the Company. However, if any such leave taken

6

by a Participant exceeds ninety (90) days, then on the one hundred eighty-first (181st) day following the commencement of such leave any Incentive Stock Option held by the Participant shall cease to be treated as an Incentive Stock Option and instead shall be treated thereafter as a Nonstatutory Stock Option, unless the Participant’s right to return to Service with the Participating Company Group is guaranteed by statute or contract. Notwithstanding the foregoing, unless otherwise designated by the Company or required by law, a leave of absence shall not be treated as Service for purposes of determining vesting under the Participant’s Award Agreement. A Participant’s Service shall be deemed to have terminated either upon an actual termination of Service or upon the entity for which the Participant performs Service ceasing to be a Participating Company. Subject to the foregoing, the Company, in its discretion, shall determine whether the Participant’s Service has terminated and the effective date of such termination.

(uu) “Stock” means the common stock of the Company, as adjusted from time to time in accordance with Section 4.2 of the Plan.

(vv) “Stock-Based Awards” means any award that is valued in whole or in part by reference to, or is otherwise based on, the Stock, including dividends on the Stock, but not limited to those Awards described in Sections 6 through 12 of the Plan.

(ww) “Subsidiary Corporation” means any present or future “subsidiary corporation” of the Company, as defined in Section 424(f) of the Code.

(xx) “Ten Percent Owner” means a Participant who, at the time an Option is granted to the Participant, owns stock possessing more than ten percent (10%) of the total combined voting power of all classes of stock of a Participating Company (other than an Affiliate) within the meaning of Section 422(b)(6) of the Code.

(yy) “Vesting Conditions” mean those conditions established in accordance with Section 9.4 or Section 11.2 of the Plan prior to the satisfaction of which shares subject to a Restricted Stock Award or Restricted Stock Unit Award, respectively, remain subject to forfeiture or a repurchase option in favor of the Company upon the Participant’s termination of Service.

2.2 Construction. Captions and titles contained herein are for convenience only and shall not affect the meaning or interpretation of any provision of the Plan. Except when otherwise indicated by the context, the singular shall include the plural and the plural shall include the singular. Use of the term “or” is not intended to be exclusive, unless the context clearly requires otherwise.

3. ADMINISTRATION.

3.1 Administration by the Committee. The Plan shall be administered by the Committee. All questions of interpretation of the Plan or of any Award shall be determined by the Committee, and such determinations shall be final and binding upon all persons having an interest in the Plan or such Award.

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3.2 Authority of Officers. Any Officer shall have the authority to act on behalf of the Company with respect to any matter, right, obligation, determination or election which is the responsibility of or which is allocated to the Company herein, provided the Officer has apparent authority with respect to such matter, right, obligation, determination or election. In addition, to the extent specified in a resolution adopted by the Board, the Chief Executive Officer of the Company shall have the authority to grant Awards to an Employee who is not an Insider and who is receiving a salary below the level which requires approval by the Committee; provided that the terms of such Awards conform to guidelines established by the Committee and provided further that at the time of making such Awards the Chief Executive Officer also is a Director.

3.3 Administration with Respect to Insiders. With respect to participation by Insiders in the Plan, at any time that any class of equity security of the Company is registered pursuant to Section 12 of the Exchange Act, the Plan shall be administered in compliance with the requirements, if any, of Rule 16b-3.

3.4 Committee Complying with Section 162(m). While the Company is a “publicly held corporation” within the meaning of Section 162(m), the Board may establish a Committee of “outside directors” within the meaning of Section 162(m) to approve the grant of any Award which might reasonably be anticipated to result in the payment of employee remuneration that would otherwise exceed the limit on employee remuneration deductible for income tax purposes pursuant to Section 162(m).

3.5 Powers of the Committee. In addition to any other powers set forth in the Plan and subject to the provisions of the Plan, the Committee shall have the full and final power and authority, in its discretion:

(a) to determine the persons to whom, and the time or times at which, Awards shall be granted and the number of shares of Stock or units to be subject to each Award based on the recommendation of the Chief Executive Officer of the Company (except that Awards to the Chief Executive Officer shall be based on the recommendation of the independent members of the Board in compliance with applicable stock exchange rules and Awards to Nonemployee Directors shall be granted automatically pursuant to Section 7 of the Plan);

(b) to determine the type of Award granted and to designate Options as Incentive Stock Options or Nonstatutory Stock Options;

(c) to determine the Fair Market Value of shares of Stock or other property;

(d) to determine the terms, conditions and restrictions applicable to each Award (which need not be identical) and any shares acquired pursuant thereto, including, without limitation, (i) the exercise or purchase price of shares purchased pursuant to any Award, (ii) the method of payment for shares purchased pursuant to any Award, (iii) the method for satisfaction of any tax withholding obligation arising in connection with Award, including by the withholding or delivery of shares of Stock, (iv) the timing, terms and conditions of the exercisability or vesting of any Award or any shares acquired pursuant thereto, (v) the Performance Award Formula and Performance Goals applicable to any Award and the extent to which such Performance Goals have been attained, (vi) the time of the expiration of any Award,

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(vii) the effect of the Participant’s termination of Service on any of the foregoing, and (viii) all other terms, conditions and restrictions applicable to any Award or shares acquired pursuant thereto not inconsistent with the terms of the Plan;

(e) to determine whether an Award will be settled in shares of Stock, cash, or in any combination thereof;

(f) to approve one or more forms of Award Agreement;

(g) to amend, modify, extend, cancel or renew any Award or to waive any restrictions or conditions applicable to any Award or any shares acquired pursuant thereto;

(h) to accelerate, continue, extend or defer the exercisability or vesting of any Award or any shares acquired pursuant thereto, including with respect to the period following a Participant’s termination of Service;

(i) without the consent of the affected Participant and notwithstanding the provisions of any Award Agreement to the contrary, to unilaterally substitute at any time a Stock Appreciation Right providing for settlement solely in shares of Stock in place of any outstanding Option, provided that such Stock Appreciation Right covers the same number of shares of Stock and provides for the same exercise price (subject in each case to adjustment in accordance with Section 4.2) as the replaced Option and otherwise provides substantially equivalent terms and conditions as the replaced Option, as determined by the Committee;

(j) to prescribe, amend or rescind rules, guidelines and policies relating to the Plan, or to adopt sub-plans or supplements to, or alternative versions of, the Plan, including, without limitation, as the Committee deems necessary or desirable to comply with the laws or regulations of or to accommodate the tax policy, accounting principles or custom of, foreign jurisdictions whose citizens may be granted Awards;

(k) to correct any defect, supply any omission or reconcile any inconsistency in the Plan or any Award Agreement and to make all other determinations and take such other actions with respect to the Plan or any Award as the Committee may deem advisable to the extent not inconsistent with the provisions of the Plan or applicable law; and

(l) to delegate to the Chief Executive Officer or the Senior Vice President of Human Resources the authority with respect to ministerial matters regarding the Plan and Awards made under the Plan.

3.6 Option or SAR Repricing/Buyout. Notwithstanding anything to the contrary set forth in the Plan, without the affirmative vote of holders of a majority of the shares of Stock cast in person or by proxy at a meeting of the shareholders of the Company at which a quorum representing a majority of all outstanding shares of Stock is present or represented by proxy, the Company shall not approve a program providing for any of the following: (a) the cancellation of outstanding Options or SARs and the grant in substitution therefore of new Options or SARs having a lower exercise price, (b) the amendment of outstanding Options or SARs to reduce the exercise price thereof or (c) the purchase of outstanding unexercised Options or SARs by the Company whether by cash payment or otherwise. This paragraph shall not be construed to apply

9

to “issuing or assuming a stock option in a transaction to which section 424(a) applies,” within the meaning of Section 424 of the Code.

3.7 Indemnification. In addition to such other rights of indemnification as they may have as members of the Board or the Committee or as officers or employees of the Participating Company Group, members of the Board or the Committee and any officers or employees of the Participating Company Group to whom authority to act for the Board, the Committee or the Company is delegated shall be indemnified by the Company against all reasonable expenses, including attorneys’ fees, actually and necessarily incurred in connection with the defense of any action, suit or proceeding, or in connection with any appeal therein, to which they or any of them may be a party by reason of any action taken or failure to act under or in connection with the Plan, or any right granted hereunder, and against all amounts paid by them in settlement thereof (provided such settlement is approved by independent legal counsel selected by the Company) or paid by them in satisfaction of a judgment in any such action, suit or proceeding, except in relation to matters as to which it shall be adjudged in such action, suit or proceeding that such person is liable for gross negligence, bad faith or intentional misconduct in duties; provided, however, that within sixty (60) days after the institution of such action, suit or proceeding, such person shall offer to the Company, in writing, the opportunity at its own expense to handle and defend the same.

4. SHARES SUBJECT TO PLAN.

4.1 Maximum Number of Shares Issuable. Subject to adjustment as provided in Section 4.2 and subject to Section 409A of the Code, the maximum aggregate number of shares of Stock that may be issued under the Plan shall be twelve million (12,000,000) and shall consist of authorized but unissued or reacquired shares of Stock or any combination thereof. If an outstanding Award for any reason expires or is terminated or canceled without having been exercised or settled in full, or if shares of Stock acquired pursuant to an Award subject to forfeiture or repurchase are forfeited or repurchased by the Company, the shares of Stock allocable to the terminated portion of such Award or such forfeited or repurchased shares of Stock shall again be available for issuance under the Plan. Shares of Stock shall not be deemed to have been issued pursuant to the Plan with respect to any portion of an Award that is settled in cash (other than in the case of Options or SARs, in which case shares of Stock having a Fair Market Value equal to the cash delivered shall be deemed issued pursuant to the Plan). In addition, shares of Stock shall not be deemed to have been issued pursuant to the Plan to the extent such shares are withheld or reacquired by the Company in satisfaction of tax withholding obligations pursuant to Section 16.2 (other than in the case of such shares withheld in connection with the exercise of Options or SARs, which shall be deemed to be issued pursuant to the Plan). Upon the exercise of an SAR, the number of shares available for issuance under the Plan shall be reduced by the gross number of shares for which the SAR is exercised. If the exercise price of an Option is paid by tender to the Company, or attestation to the ownership, of shares of Stock owned by the Participant, or by means of a Net-Exercise, the number of shares available for issuance under the Plan shall be reduced by the gross number of shares for which the Option is exercised.

4.2 Adjustments for Changes in Capital Structure. Subject to any required action by the shareholders of the Company, in the event of any change in the Stock effected without

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receipt of consideration by the Company, whether through merger, consolidation, reorganization, reincorporation, recapitalization, reclassification, stock dividend, stock split, reverse stock split, split-up, split-off, spin-off, combination of shares, exchange of shares, or similar change in the capital structure of the Company, or in the event of payment of a dividend or distribution to the shareholders of the Company in a form other than Stock (excepting normal cash dividends) that has a material effect on the Fair Market Value of shares of Stock, appropriate adjustments shall be made in the number and kind of shares subject to the Plan and to any outstanding Awards, in the Award limits set forth in Section 5.4, in the Nonemployee Director Awards to be granted automatically pursuant to Section 7, and in the exercise or purchase price per share under any outstanding Award in order to prevent dilution or enlargement of Participants’ rights under the Plan. For purposes of the foregoing, conversion of any convertible securities of the Company shall not be treated as “effected without receipt of consideration by the Company.” Any fractional share resulting from an adjustment pursuant to this Section 4.2 shall be rounded down to the nearest whole number. The Committee in its sole discretion, may also make such adjustments in the terms of any Award to reflect, or related to, such changes in the capital structure of the Company or distributions as it deems appropriate, including modification of Performance Goals, Performance Award Formulas and Performance Periods. The adjustments determined by the Committee pursuant to this Section 4.2 shall be final, binding and conclusive.

5. ELIGIBILITY AND AWARD LIMITATIONS.

5.1 Persons Eligible for Awards. Awards may be granted only to Employees, Consultants and Directors. For purposes of the foregoing sentence, “Employees,” “Consultants”and “Directors” shall include prospective Employees, prospective Consultants and prospective Directors to whom Awards are granted in connection with written offers of an employment or other service relationship with the Participating Company Group; provided, however, that no Stock subject to any such Award shall vest, become exercisable or be issued prior to the date on which such person commences Service. A Nonemployee Director Award may be granted only to a person who, at the time of grant, is a Nonemployee Director.

5.2 Participation. Awards other than Nonemployee Director Awards are granted solely at the discretion of the Committee. Eligible persons may be granted more than one Award. However, excepting Nonemployee Director Awards, eligibility in accordance with this Section shall not entitle any person to be granted an Award, or, having been granted an Award, to be granted an additional Award.

5.3 Incentive Stock Option Limitations.

(a) Persons Eligible. An Incentive Stock Option may be granted only to a person who, on the effective date of grant, is an Employee of the Company, a Parent Corporation or a Subsidiary Corporation (each being an “ISO-Qualifying Corporation”). Any person who is not an Employee of an ISO-Qualifying Corporation on the effective date of the grant of an Option to such person may be granted only a Nonstatutory Stock Option. An Incentive Stock Option granted to a prospective Employee upon the condition that such person become an Employee of an ISO-Qualifying Corporation shall be deemed granted effective on the date such person commences Service with an ISO-Qualifying Corporation, with an exercise price determined as of such date in accordance with Section 6.1.

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(b) Fair Market Value Limitation. To the extent that options designated as Incentive Stock Options (granted under all stock option plans of the Participating Company Group, including the Plan) become exercisable by a Participant for the first time during any calendar year for stock having a Fair Market Value greater than One Hundred Thousand Dollars ($100,000), the portion of such options which exceeds such amount shall be treated as Nonstatutory Stock Options. For purposes of this Section, options designated as Incentive Stock Options shall be taken into account in the order in which they were granted, and the Fair Market Value of stock shall be determined as of the time the option with respect to such stock is granted. If the Code is amended to provide for a limitation different from that set forth in this Section, such different limitation shall be deemed incorporated herein effective as of the date and with respect to such Options as required or permitted by such amendment to the Code. If an Option is treated as an Incentive Stock Option in part and as a Nonstatutory Stock Option in part by reason of the limitation set forth in this Section, the Participant may designate which portion of such Option the Participant is exercising. In the absence of such designation, the Participant shall be deemed to have exercised the Incentive Stock Option portion of the Option first. Upon exercise, shares issued pursuant to each such portion shall be separately identified.

5.4 Award Limits.

(a) Maximum Number of Shares Issuable Pursuant to Incentive Stock Options. Subject to adjustment as provided in Section 4.2, the maximum aggregate number of shares of Stock that may be issued under the Plan pursuant to the exercise of Incentive Stock Options shall not exceed twelve million (12,000,000) shares. The maximum aggregate number of shares of Stock that may be issued under the Plan pursuant to all Awards other than Incentive Stock Options shall be the number of shares determined in accordance with Section 4.1, subject to adjustment as provided in Section 4.2 and further subject to the limitation set forth in Section 5.4(b) below.

(b) Aggregate Limit on Full Value Awards. Subject to adjustment as provided in Section 4.2, in no event shall more than twelve million (12,000,000) shares in the aggregate be issued under the Plan pursuant to the exercise or settlement of Restricted Stock Awards, Restricted Stock Unit Awards and Performance Awards (“Full Value Awards”). Except with respect to a maximum of five percent (5%) of the shares of Stock authorized in this Section 5.4(b), any Full Value Awards which vest on the basis of the Participant’s continued Service shall not provide for vesting which is any more rapid than annual pro rata vesting over a three (3) year period and any Full Value Awards which vest upon the attainment of Performance Goals shall provide for a Performance Period of at least twelve (12) months.

(c) Section 162(m) Award Limits. The following limits shall apply to the grant of any Award if, at the time of grant, the Company is a “publicly held corporation” within the meaning of Section 162(m).

(i) Options and SARs. Subject to adjustment as provided in Section 4.2, no Employee shall be granted within any fiscal year of the Company one or more Options or Freestanding SARs which in the aggregate are for more than 400,000 shares of Stock reserved for issuance under the Plan.

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(ii) Restricted Stock and Restricted Stock Unit Awards. Subject to adjustment as provided in Section 4.2, no Employee shall be granted within any fiscal year of the Company one or more Restricted Stock Awards or Restricted Stock Unit Awards, subject to Vesting Conditions based on the attainment of Performance Goals, for more than 400,000 shares of Stock reserved for issuance under the Plan.

(iii) Performance Awards. Subject to adjustment as provided in Section 4.2, no Employee shall be granted (1) one or more awards of Performance Shares which could result in such Employee receiving more than 400,000 shares of Stock reserved for issuance under the Plan for each full fiscal year of the Company contained in the Performance Period for such Award, and (2) one or more awards of Performance Units which could result in such Employee receiving more than five million dollars ($5 million) for each full fiscal year of the Company contained in the Performance Period for such Award, with such amount to be pro-rated for Performance Periods of less than one full fiscal year.

6. TERMS AND CONDITIONS OF OPTIONS.

Options shall be evidenced by Award Agreements specifying the number of shares of Stock covered thereby, in such form as the Committee shall from time to time establish. No Option or purported Option shall be a valid and binding obligation of the Company unless evidenced by a fully executed Award Agreement. Award Agreements evidencing Options may incorporate all or any of the terms of the Plan by reference and, except as otherwise set forth in Section 7 with respect to Nonemployee Director Options, if any, shall comply with and be subject to the following terms and conditions:

6.1 Exercise Price. The exercise price for each Option shall be established in the discretion of the Committee; provided, however, that (a) the exercise price per share shall be not less than the Fair Market Value of a share of Stock on the effective date of grant of the Option and (b) no Incentive Stock Option granted to a Ten Percent Owner shall have an exercise price per share less than one hundred ten percent (110%) of the Fair Market Value of a share of Stock on the effective date of grant of the Option. Notwithstanding the foregoing, an Option (whether an Incentive Stock Option or a Nonstatutory Stock Option) may be granted with an exercise price lower than the minimum exercise price set forth above if such Option is granted pursuant to an assumption or substitution for another option in a manner qualifying under the provisions of Section 424(a) of the Code.

6.2 Exercisability and Term of Options. Options shall be exercisable at such time or times, or upon such event or events, and subject to such terms, conditions, performance criteria and restrictions as shall be determined by the Committee and set forth in the Award Agreement evidencing such Option; provided, however, that (a) no Option shall be exercisable after the expiration of ten (10) years after the effective date of grant of such Option, (b) no Incentive Stock Option granted to a Ten Percent Owner shall be exercisable after the expiration of five (5) years after the effective date of grant of such Option, and (c) no Option granted to a prospective Employee, prospective Consultant or prospective Director may become exercisable prior to the date on which such person commences Service. Subject to the foregoing, unless otherwise specified by the Committee in the grant of an Option, any Option granted hereunder

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shall terminate ten (10) years after the effective date of grant of the Option, unless earlier terminated in accordance with its provisions.

6.3 Payment of Exercise Price.

(a) Forms of Consideration Authorized. Except as otherwise provided below, payment of the exercise price for the number of shares of Stock being purchased pursuant to any Option shall be made (i) in cash, by check or in cash equivalent, (ii) by tender to the Company, or attestation to the ownership, of shares of Stock owned by the Participant having a Fair Market Value not less than the exercise price, (iii) by delivery of a properly executed notice of exercise together with irrevocable instructions to a broker providing for the assignment to the Company of the proceeds of a sale or loan with respect to some or all of the shares being acquired upon the exercise of the Option (including, without limitation, through an exercise complying with the provisions of Regulation T as promulgated from time to time by the Board of Governors of the Federal Reserve System) (a “Cashless Exercise”), (iv) by delivery of a properly executed notice of exercise electing a Net-Exercise, (v) by such other consideration as may be approved by the Committee from time to time to the extent permitted by applicable law, or (vi) by any combination thereof. The Committee may at any time or from time to time grant Options which do not permit all of the foregoing forms of consideration to be used in payment of the exercise price or which otherwise restrict one or more forms of consideration.

(b) Limitations on Forms of Consideration.

(i) Tender of Stock. Notwithstanding the foregoing, an Option may not be exercised by tender to the Company, or attestation to the ownership, of shares of Stock to the extent such tender or attestation would constitute a violation of the provisions of any law, regulation or agreement restricting the redemption of the Company’s stock.

(ii) Cashless Exercise. The Company reserves, at any and all times, the right, in the Company’s sole and absolute discretion, to establish, decline to approve or terminate any program or procedures for the exercise of Options by means of a Cashless Exercise, including with respect to one or more Participants specified by the Company notwithstanding that such program or procedures may be available to other Participants.

6.4 Effect of Termination of Service.

(a) Option Exercisability. Subject to earlier termination of the Option as otherwise provided herein and unless otherwise provided by the Committee, an Option shall be exercisable after a Participant’s termination of Service only during the applicable time periods provided in the Award Agreement.

(b) Extension if Exercise Prevented by Law. Notwithstanding the foregoing, unless the Committee provides otherwise in the Award Agreement, if the exercise of an Option within the applicable time periods is prevented by the provisions of Section 14.1 below, the Option shall remain exercisable until three (3) months (or such longer period of time as determined by the Committee, in its discretion) after the date the Participant is notified by the

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Company that the Option is exercisable, but in any event no later than the Option Expiration Date.

(c) Extension if Participant Subject to Section 16(b). Notwithstanding the foregoing, if a sale within the applicable time periods of shares acquired upon the exercise of the Option would subject the Participant to suit under Section 16(b) of the Exchange Act, the Option shall remain exercisable until the earliest to occur of (i) the tenth (10th) day following the date on which a sale of such shares by the Participant would no longer be subject to such suit, (ii) the one hundred and ninetieth (190th) day after the Participant’s termination of Service, or (iii) the Option Expiration Date.

6.5 Transferability of Options. During the lifetime of the Participant, an Option shall be exercisable only by the Participant or the Participant’s guardian or legal representative. Prior to the issuance of shares of Stock upon the exercise of an Option, the Option shall not be subject in any manner to anticipation, alienation, sale, exchange, transfer, assignment, pledge, encumbrance, or garnishment by creditors of the Participant or the Participant’s beneficiary, except transfer by will or by the laws of descent and distribution. Notwithstanding the foregoing, to the extent permitted by the Committee, in its discretion, and set forth in the Award Agreement evidencing such Option, a Nonstatutory Stock Option shall be assignable or transferable subject to the applicable limitations, if any, described in the General Instructions to Form S-8 Registration Statement under the Securities Act.

7. TERMS AND CONDITIONS OF NONEMPLOYEE DIRECTOR AWARDS.

Nonemployee Director Awards granted under this Plan shall be automatic and non-discretionary and shall comply with and be subject to the terms and conditions set forth in this Section 7.

For purposes of this Section 7 as amended on December 15, 2010, the grant date for all Nonemployee Director awards to be made under this Section 7 shall be the date on which the independent inspector of election certifies the results of the annual election of directors by shareholders of PG&E Corporation; provided, however, that in extraordinary circumstances, the grant shall be delayed until the first business day of the next open trading window period following certification of the director election results, as determined by the General Counsel of PG&E Corporation (the “Grant Date”)

Grants made pursuant to this Section 7, but prior to December 15, 2010, shall be subject to the terms of the Plan in effect at the time of grant.

7.1 Grant of Restricted Stock Unit.

(a) Timing and Amount of Grant. Each person who is a Nonemployee Director on the Grant Date shall receive a grant of Restricted Stock Units with the number of Restricted Stock Units determined by dividing $90,000 by the Fair Market Value of the Stock on the Grant Date (including fractions computed to three decimal places). The Restricted Stock Units awarded to a Nonemployee Director shall be credited to the director’s Restricted Stock Unit account. Each Restricted Stock Unit awarded to a Nonemployee Director in accordance with this Section 7.1(a) shall be deemed to be equal to one (1) (or fraction thereof) share of Stock

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on the Grant Date, and the value of the Restricted Stock Unit shall thereafter fluctuate in value in accordance with the Fair Market Value of the Stock. No person shall receive more than one grant of Restricted Stock Units pursuant to this Section 7.1(a) during any calendar year.

(b) Dividend Rights. Each Nonemployee Director’s Restricted Stock Unit account shall be credited quarterly on each dividend payment date with additional shares of Restricted Stock Units (including fractions computed to three decimal places) determined by dividing (1) the amount of cash dividends paid on such date with respect to the number of shares of Stock represented by the Restricted Stock Units previously credited to the account by (2) the Fair Market Value per share of Stock on such date. Such additional Restricted Stock Units shall be subject to the same terms and conditions and shall be settled in the same manner and at the same time as the Restricted Stock Units originally subject to the Restricted Stock Unit Award.

(c) Settlement of Restricted Stock Units. Restricted Stock Units credited to a Nonemployee Director’s Restricted Stock Unit account shall be settled in a lump sum by the issuance of an equal number of shares of Stock, rounded down to the nearest whole share, upon the earliest of (i) the first anniversary of the Grant Date (normal vesting date), (ii) the Nonemployee Director’s death, (iii) the Nonemployee Director’s Disability (within the meaning of Section 409A of the Code), (iv) a Change in Control that also constitutes a Section 409A Change in Control, or (v) the Nonemployee Director’s Separation from Service following a Change in Control.

7.2 Effect of Termination of Service as a Nonemployee Director.

(a) Forfeiture of Award. If the Nonemployee Director has a Separation from Service prior to the normal vesting date, other than for the occurrence of any of the distribution events set forth in Section 7.1(c), all Restricted Stock Units credited to the Participant’s account shall be forfeited to the Company and from and after the date of such Separation from Service, and the Participant shall cease to have any rights with respect thereto; provided, however, that if the Nonemployee Director Separates from Service due to a pending Disability determination, such forfeiture shall not occur until a finding that such Disability has not occurred.

(b) Death or Disability. If the Nonemployee Director becomes “disabled,” within the meaning of Section 409A of the Code or in the event of the Nonemployee Director’s death, all Restricted Stock Units credited to the Nonemployee Director’s account shall immediately vest and become payable, in accordance with Section 7.1(c), to the Participant (or the Participant’s legal representative or other person who acquired the rights to the Restricted Stock Units by reason of the Participant’s death) in the form of a number of shares of Stock equal to the number of Restricted Stock Units credited to the Restricted Stock Unit account, rounded down to the nearest whole share.

(c) Notwithstanding the provisions of Section 7.1(c) above, the Board, in its sole discretion, may establish different terms and conditions pertaining to Nonemployee Director Awards.

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7.3 Effect of Change in Control on Nonemployee Director Awards. Upon the occurrence of a Change in Control, all Restricted Stock Units shall immediately vest but shall not be settled until the first of the events specified in Section 7.1(c) occurs.

8. TERMS AND CONDITIONS OF STOCK APPRECIATION RIGHTS.

Stock Appreciation Rights shall be evidenced by Award Agreements specifying the number of shares of Stock subject to the Award, in such form as the Committee shall from time to time establish. No SAR or purported SAR shall be a valid and binding obligation of the Company unless evidenced by a fully executed Award Agreement. Award Agreements evidencing SARs may incorporate all or any of the terms of the Plan by reference and shall comply with and be subject to the following terms and conditions:

8.1 Types of SARs Authorized. SARs may be granted in tandem with all or any portion of a related Option (a “Tandem SAR”) or may be granted independently of any Option (a “Freestanding SAR”). A Tandem SAR may be granted either concurrently with the grant of the related Option or at any time thereafter prior to the complete exercise, termination, expiration or cancellation of such related Option.

8.2 Exercise Price. The exercise price for each SAR shall be established in the discretion of the Committee; provided, however, that (a) the exercise price per share subject to a Tandem SAR shall be the exercise price per share under the related Option and (b) the exercise price per share subject to a Freestanding SAR shall be not less than the Fair Market Value of a share of Stock on the effective date of grant of the SAR.

8.3 Exercisability and Term of SARs.

(a) Tandem SARs. Tandem SARs shall be exercisable only at the time and to the extent, and only to the extent, that the related Option is exercisable, subject to such provisions as the Committee may specify where the Tandem SAR is granted with respect to less than the full number of shares of Stock subject to the related Option.

(b) Freestanding SARs. Freestanding SARs shall be exercisable at such time or times, or upon such event or events, and subject to such terms, conditions, performance criteria and restrictions as shall be determined by the Committee and set forth in the Award Agreement evidencing such SAR; provided, however, that no Freestanding SAR shall be exercisable after the expiration of ten (10) years after the effective date of grant of such SAR.

8.4 Deemed Exercise of SARs. If, on the date on which an SAR would otherwise terminate or expire, the SAR by its terms remains exercisable immediately prior to such termination or expiration and, if so exercised, would result in a payment to the holder of such SAR, then any portion of such SAR which has not previously been exercised shall automatically be deemed to be exercised as of such date with respect to such portion.

8.5 Effect of Termination of Service. Subject to earlier termination of the SAR as otherwise provided herein and unless otherwise provided by the Committee in the grant of an SAR and set forth in the Award Agreement, an SAR shall be exercisable after a Participant’s termination of Service only as provided in the Award Agreement.

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8.6 Nontransferability of SARs. During the lifetime of the Participant, an SAR shall be exercisable only by the Participant or the Participant’s guardian or legal representative. Prior to the exercise of an SAR, the SAR shall not be subject in any manner to anticipation, alienation, sale, exchange, transfer, assignment, pledge, encumbrance, or garnishment by creditors of the Participant or the Participant’s beneficiary, except transfer by will or by the laws of descent and distribution.

9. TERMS AND CONDITIONS OF RESTRICTED STOCK AWARDS.

Restricted Stock Awards shall be evidenced by Award Agreements specifying the number of shares of Stock subject to the Award, in such form as the Committee shall from time to time establish. No Restricted Stock Award or purported Restricted Stock Award shall be a valid and binding obligation of the Company unless evidenced by a fully executed Award Agreement. Award Agreements evidencing Restricted Stock Awards may incorporate all or any of the terms of the Plan by reference and shall comply with and be subject to the following terms and conditions:

9.1 Types of Restricted Stock Awards Authorized. Restricted Stock Awards may or may not require the payment of cash compensation for the stock. Restricted Stock Awards may be granted upon such conditions as the Committee shall determine, including, without limitation, upon the attainment of one or more Performance Goals described in Section 10.4. If either the grant of a Restricted Stock Award or the lapsing of the Restriction Period is to be contingent upon the attainment of one or more Performance Goals, the Committee shall follow procedures substantially equivalent to those set forth in Sections 10.3 through 10.5(a).

9.2 Purchase Price. The purchase price, if any, for shares of Stock issuable under each Restricted Stock Award and the means of payment shall be established by the Committee in its discretion.

9.3 Purchase Period. A Restricted Stock Award requiring the payment of cash consideration shall be exercisable within a period established by the Committee; provided, however, that no Restricted Stock Award granted to a prospective Employee, prospective Consultant or prospective Director may become exercisable prior to the date on which such person commences Service.

9.4 Vesting and Restrictions on Transfer. Shares issued pursuant to any Restricted Stock Award may or may not be made subject to Vesting Conditions based upon the satisfaction of such Service requirements, conditions, restrictions or performance criteria, including, without limitation, Performance Goals as described in Section 10.4, as shall be established by the Committee and set forth in the Award Agreement evidencing such Award. During any Restriction Period in which shares acquired pursuant to a Restricted Stock Award remain subject to Vesting Conditions, such shares may not be sold, exchanged, transferred, pledged, assigned or otherwise disposed of other than as provided in the Award Agreement or as provided in Section 9.7. Upon request by the Company, each Participant shall execute any agreement evidencing such transfer restrictions prior to the receipt of shares of Stock hereunder and shall promptly present to the Company any and all certificates representing shares of Stock acquired

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hereunder for the placement on such certificates of appropriate legends evidencing any such transfer restrictions.

9.5 Voting Rights, Dividends and Distributions. Except as provided in this Section, Section 9.4 and any Award Agreement, during the Restriction Period applicable to shares subject to a Restricted Stock Award, the Participant shall have all of the rights of a shareholder of the Company holding shares of Stock, including the right to vote such shares and to receive all dividends and other distributions paid with respect to such shares. However, in the event of a dividend or distribution paid in shares of Stock or any other adjustment made upon a change in the capital structure of the Company as described in Section 4.2, any and all new, substituted or additional securities or other property (other than normal cash dividends) to which the Participant is entitled by reason of the Participant’s Restricted Stock Award shall be immediately subject to the same Vesting Conditions as the shares subject to the Restricted Stock Award with respect to which such dividends or distributions were paid or adjustments were made.

9.6 Effect of Termination of Service. Unless otherwise provided by the Committee in the grant of a Restricted Stock Award and set forth in the Award Agreement, if a Participant’s Service terminates for any reason, whether voluntary or involuntary (including the Participant’s death or disability), then the Participant shall forfeit to the Company any shares acquired by the Participant pursuant to a Restricted Stock Award which remain subject to Vesting Conditions as of the date of the Participant’s termination of Service in exchange for the payment of the purchase price, if any, paid by the Participant. The Company shall have the right to assign at any time any repurchase right it may have, whether or not such right is then exercisable, to one or more persons as may be selected by the Company.

9.7 Nontransferability of Restricted Stock Award Rights. Prior to the issuance of shares of Stock pursuant to a Restricted Stock Award, rights to acquire such shares shall not be subject in any manner to anticipation, alienation, sale, exchange, transfer, assignment, pledge, encumbrance or garnishment by creditors of the Participant or the Participant’s beneficiary, except transfer by will or the laws of descent and distribution. All rights with respect to a Restricted Stock Award granted to a Participant hereunder shall be exercisable during his or her lifetime only by such Participant or the Participant’s guardian or legal representative.

10. TERMS AND CONDITIONS OF PERFORMANCE AWARDS.

Performance Awards shall be evidenced by Award Agreements in such form as the Committee shall from time to time establish. No Performance Award or purported Performance Award shall be a valid and binding obligation of the Company unless evidenced by a fully executed Award Agreement. Award Agreements evidencing Performance Awards may incorporate all or any of the terms of the Plan by reference and shall comply with and be subject to the following terms and conditions:

10.1 Types of Performance Awards Authorized. Performance Awards may be in the form of either Performance Shares or Performance Units. Each Award Agreement evidencing a Performance Award shall specify the number of Performance Shares or Performance Units

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subject thereto, the Performance Award Formula, the Performance Goal(s) and Performance Period applicable to the Award, and the other terms, conditions and restrictions of the Award.

10.2 Initial Value of Performance Shares and Performance Units. Unless otherwise provided by the Committee in granting a Performance Award, each Performance Share shall have an initial value equal to the Fair Market Value of one (1) share of Stock, subject to adjustment as provided in Section 4.2, on the effective date of grant of the Performance Share. Each Performance Unit shall have an initial value determined by the Committee. The final value payable to the Participant in settlement of a Performance Award determined on the basis of the applicable Performance Award Formula will depend on the extent to which Performance Goals established by the Committee are attained within the applicable Performance Period established by the Committee.

10.3 Establishment of Performance Period, Performance Goals and Performance Award Formula. In granting each Performance Award, the Committee shall establish in writing the applicable Performance Period, Performance Award Formula and one or more Performance Goals which, when measured at the end of the Performance Period, shall determine on the basis of the Performance Award Formula the final value of the Performance Award to be paid to the Participant. To the extent compliance with the requirements under Section 162(m) with respect to “performance-based compensation” is desired, the Committee shall establish the Performance Goal(s) and Performance Award Formula applicable to each Performance Award no later than the earlier of (a) the date ninety (90) days after the commencement of the applicable Performance Period or (b) the date on which 25% of the Performance Period has elapsed, and, in any event, at a time when the outcome of the Performance Goals remains substantially uncertain. Once established, the Performance Goals and Performance Award Formula shall not be changed during the Performance Period. The Company shall notify each Participant granted a Performance Award of the terms of such Award, including the Performance Period, Performance Goal(s) and Performance Award Formula.

10.4 Measurement of Performance Goals. Performance Goals shall be established by the Committee on the basis of targets to be attained (“Performance Targets”) with respect to one or more measures of business or financial performance (each, a “Performance Measure”), subject to the following:

(a) Performance Measures. Performance Measures shall be calculated with respect to the Company and/or each Subsidiary Corporation and/or such division or other business unit as may be selected by the Committee. Performance Measures may be based upon one or more of the following objectively defined and non-discretionary business criteria and any other objectively verifiable and non-discretionary adjustments permitted and pre-established by the Committee in accordance with Section 162(m), as determined by the Committee: (i) sales revenue; (ii) gross margin; (iii) operating margin; (iv) operating income; (v) pre-tax profit; (vi) earnings before interest, taxes and depreciation and amortization (EBITDA)/adjusted EBITDA; (vii) net income; (viii) expenses; (ix) the market price of the Stock; (x) earnings per share; (xi) return on shareholder equity or assets; (xii) return on capital; (xiii) return on net assets; (xiv) economic profit or economic value added (EVA); (xv) market share; (xvi) customer satisfaction; (xvii) safety; (xviii) total shareholder return; (xix) earnings; (xx) cash flow; (xxi) revenue; (xxii) profits before interest and taxes; (xxiii) profit/loss; (xxiv) profit margin; (xxv)

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working capital; (xxvi) price/earnings ratio; (xxvii) debt or debt-to-equity; (xxviii) accounts receivable; (xxix) write-offs; (xxx) cash; (xxxi) assets; (xxxii) liquidity; (xxxiii) earnings from operations; (xxxiv) operational reliability; (xxxv) environmental performance; (xxxvi) funds from operations; (xxxvii) adjusted revenues; (xxxviii) free cash flow; or (xxxix) core earnings.

(b) Performance Targets. Performance Targets may include a minimum, maximum, target level and intermediate levels of performance, with the final value of a Performance Award determined under the applicable Performance Award Formula by the level attained during the applicable Performance Period. A Performance Target may be stated as an absolute value or as a value determined relative to a standard selected by the Committee.

10.5 Settlement of Performance Awards.

(a) Determination of Final Value. As soon as practicable, but no later than the 15th day of the third month following the completion of the Performance Period applicable to a Performance Award, the Committee shall certify in writing the extent to which the applicable Performance Goals have been attained and the resulting final value of the Award earned by the Participant and to be paid upon its settlement in accordance with the applicable Performance Award Formula.

(b) Discretionary Adjustment of Award Formula. In its discretion, the Committee may, either at the time it grants a Performance Award or at any time thereafter, provide for the positive or negative adjustment of the Performance Award Formula applicable to a Performance Award that is not intended to constitute “qualified performance based compensation” to a “covered employee” within the meaning of Section 162(m) (a “Covered Employee”) to reflect such Participant’s individual performance in his or her position with the Company or such other factors as the Committee may determine. With respect to a Performance Award intended to constitute qualified performance-based compensation to a Covered Employee, the Committee shall have the discretion to reduce some or all of the value of the Performance Award that would otherwise be paid to the Covered Employee upon its settlement notwithstanding the attainment of any Performance Goal and the resulting value of the Performance Award determined in accordance with the Performance Award Formula.

(c) Payment in Settlement of Performance Awards. As soon as practicable following the Committee’s determination and certification in accordance with Sections 10.5(a) and (b) but, in any case, no later than the 15th day of the third month following completion of the Performance Period applicable to a Performance Award, payment shall be made to each eligible Participant (or such Participant’s legal representative or other person who acquired the right to receive such payment by reason of the Participant’s death) of the final value of the Participant’s Performance Award. Payment of such amount shall be made in cash, shares of Stock, or a combination thereof as determined by the Committee.

10.6 Voting Rights, Dividend Equivalent Rights and Distributions. Participants shall have no voting rights with respect to shares of Stock represented by Performance Share Awards until the date of the issuance of such shares, if any (as evidenced by the appropriate entry on the books of the Company or of a duly authorized transfer agent of the Company). However, the Committee, in its discretion, may provide in the Award Agreement evidencing any

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Performance Share Award that the Participant shall be entitled to receive Dividend Equivalents with respect to the payment of cash dividends on Stock having a record date prior to the date on which the Performance Shares are settled or forfeited. Such Dividend Equivalents, if any, shall be credited to the Participant in the form of additional whole Performance Shares as of the date of payment of such cash dividends on Stock. The number of additional Performance Shares (rounded to the nearest whole number) to be so credited shall be determined by dividing (a) the amount of cash dividends paid on such date with respect to the number of shares of Stock represented by the Performance Shares previously credited to the Participant by (b) the Fair Market Value per share of Stock on such date. Dividend Equivalents may be paid currently or may be accumulated and paid to the extent that Performance Shares become nonforfeitable, as determined by the Committee in accordance with Section 409A of the Code. Settlement of Dividend Equivalents may be made in cash, shares of Stock, or a combination thereof as determined by the Committee, and may be paid on the same basis as settlement of the related Performance Share as provided in Section 10.5. Dividend Equivalents shall not be paid with respect to Performance Units. In the event of a dividend or distribution paid in shares of Stock or any other adjustment made upon a change in the capital structure of the Company as described in Section 4.2, appropriate adjustments shall be made in the Participant’s Performance Share Award so that it represents the right to receive upon settlement any and all new, substituted or additional securities or other property (other than normal cash dividends) to which the Participant would be entitled by reason of the shares of Stock issuable upon settlement of the Performance Share Award, and all such new, substituted or additional securities or other property shall be immediately subject to the same Performance Goals as are applicable to the Award.

10.7 Effect of Termination of Service. Unless otherwise provided by the Committee in the grant of a Performance Award and set forth in the Award Agreement, the effect of a Participant’s termination of Service on the Performance Award shall be as follows:

(a) Death or Disability. If the Participant’s Service terminates because of the death or Disability of the Participant before the completion of the Performance Period applicable to the Performance Award, the final value of the Participant’s Performance Award shall be determined by the extent to which the applicable Performance Goals have been attained with respect to the entire Performance Period and shall be prorated based on the number of months of the Participant’s Service during the Performance Period. Payment shall be made following the end of the Performance Period in any manner permitted by Section 10.5.

(b) Other Termination of Service. If the Participant’s Service terminates for any reason except death or Disability before the completion of the Performance Period applicable to the Performance Award, such Award shall be forfeited in its entirety; provided, however, that in the event of an involuntary termination of the Participant’s Service, the Committee, in its sole discretion, may waive the automatic forfeiture of all or any portion of any such Award.

10.8 Nontransferability of Performance Awards. Prior to settlement in accordance with the provisions of the Plan, no Performance Award shall be subject in any manner to anticipation, alienation, sale, exchange, transfer, assignment, pledge, encumbrance, or garnishment by creditors of the Participant or the Participant’s beneficiary, except transfer by

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will or by the laws of descent and distribution. All rights with respect to a Performance Award granted to a Participant hereunder shall be exercisable during his or her lifetime only by such Participant or the Participant’s guardian or legal representative.

11. TERMS AND CONDITIONS OF RESTRICTED STOCK UNIT AWARDS.

Restricted Stock Unit Awards shall be evidenced by Award Agreements specifying the number of Restricted Stock Units subject to the Award, in such form as the Committee shall from time to time establish. No Restricted Stock Unit Award or purported Restricted Stock Unit Award shall be a valid and binding obligation of the Company unless evidenced by a fully executed Award Agreement. Award Agreements evidencing Restricted Stock Units may incorporate all or any of the terms of the Plan by reference and shall comply with and be subject to the following terms and conditions:

11.1 Grant of Restricted Stock Unit Awards. Restricted Stock Unit Awards may be granted upon such conditions as the Committee shall determine, including, without limitation, upon the attainment of one or more Performance Goals described in Section 10.4. If either the grant of a Restricted Stock Unit Award or the Vesting Conditions with respect to such Award is to be contingent upon the attainment of one or more Performance Goals, the Committee shall follow procedures substantially equivalent to those set forth in Sections 10.3 through 10.5(a).

11.2 Vesting. Restricted Stock Units may or may not be made subject to Vesting Conditions based upon the satisfaction of such Service requirements, conditions, restrictions or performance criteria, including, without limitation, Performance Goals as described in Section 10.4, as shall be established by the Committee and set forth in the Award Agreement evidencing such Award.

11.3 Voting Rights, Dividend Equivalent Rights and Distributions. Participants shall have no voting rights with respect to shares of Stock represented by Restricted Stock Units until the date of the issuance of such shares (as evidenced by the appropriate entry on the books of the Company or of a duly authorized transfer agent of the Company). However, the Committee, in its discretion, may provide in the Award Agreement evidencing any Restricted Stock Unit Award that the Participant shall be entitled to receive Dividend Equivalents with respect to the payment of cash dividends on Stock having a record date prior to the date on which Restricted Stock Units held by such Participant are settled. Such Dividend Equivalents, if any, shall be paid by crediting the Participant with additional whole Restricted Stock Units as of the date of payment of such cash dividends on Stock. The number of additional Restricted Stock Units (rounded to the nearest whole number) to be so credited shall be determined by dividing (a) the amount of cash dividends paid on such date with respect to the number of shares of Stock represented by the Restricted Stock Units previously credited to the Participant by (b) the Fair Market Value per share of Stock on such date. Such additional Restricted Stock Units shall be subject to the same terms and conditions and shall be settled in the same manner and at the same time as the Restricted Stock Units originally subject to the Restricted Stock Unit Award, provided that Dividend Equivalents may be settled in cash, shares of Stock, or a combination thereof as determined by the Committee. In the event of a dividend or distribution paid in shares of Stock or any other adjustment made upon a change in the capital structure of the Company as described in Section 4.2, appropriate adjustments shall be made in the Participant’s Restricted

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Stock Unit Award so that it represents the right to receive upon settlement any and all new, substituted or additional securities or other property (other than normal cash dividends) to which the Participant would be entitled by reason of the shares of Stock issuable upon settlement of the Award, and all such new, substituted or additional securities or other property shall be immediately subject to the same Vesting Conditions as are applicable to the Award.

11.4 Effect of Termination of Service. Unless otherwise provided by the Committee in the grant of a Restricted Stock Unit Award and set forth in the Award Agreement, if a Participant’s Service terminates for any reason, whether voluntary or involuntary (including the Participant’s death or disability), then the Participant shall forfeit to the Company any Restricted Stock Units pursuant to the Award which remain subject to Vesting Conditions as of the date of the Participant’s termination of Service.

11.5 Settlement of Restricted Stock Unit Awards . The Company shall issue to a Participant on the date on which Restricted Stock Units subject to the Participant’s Restricted Stock Unit Award vest or on such other date determined by the Committee, in its discretion, and set forth in the Award Agreement one (1) share of Stock (and/or any other new, substituted or additional securities or other property pursuant to an adjustment described in Section 11.3) for each Restricted Stock Unit then becoming vested or otherwise to be settled on such date, subject to the withholding of applicable taxes. Notwithstanding the foregoing, if permitted by the Committee and set forth in the Award Agreement, the Participant may elect in accordance with terms specified in the Award Agreement to defer receipt of all or any portion of the shares of Stock or other property otherwise issuable to the Participant pursuant to this Section.

11.6 Nontransferability of Restricted Stock Unit Awards. Prior to the issuance of shares of Stock in settlement of a Restricted Stock Unit Award, the Award shall not be subject in any manner to anticipation, alienation, sale, exchange, transfer, assignment, pledge, encumbrance, or garnishment by creditors of the Participant or the Participant’s beneficiary, except transfer by will or by the laws of descent and distribution. All rights with respect to a Restricted Stock Unit Award granted to a Participant hereunder shall be exercisable during his or her lifetime only by such Participant or the Participant’s guardian or legal representative.

12. DEFERRED COMPENSATION AWARDS.

12.1 Establishment of Deferred Compensation Award Programs. This Section 12 shall not be effective unless and until the Committee determines to establish a program pursuant to this Section. The Committee, in its discretion and upon such terms and conditions as it may determine, may establish one or more programs pursuant to the Plan under which:

(a) Participants designated by the Committee who are Insiders or otherwise among a select group of highly compensated Employees may irrevocably elect, prior to a date specified by the Committee, to reduce such Participant’s compensation otherwise payable in cash (subject to any minimum or maximum reductions imposed by the Committee) and to be granted automatically at such time or times as specified by the Committee one or more Awards of Stock Units with respect to such numbers of shares of Stock as determined in accordance with the rules of the program established by the Committee and having such other terms and conditions as established by the Committee.

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(b) Participants designated by the Committee who are Insiders or otherwise among a select group of highly compensated Employees may irrevocably elect, prior to a date specified by the Committee, to be granted automatically an Award of Stock Units with respect to such number of shares of Stock and upon such other terms and conditions as established by the Committee in lieu of cash or shares of Stock otherwise issuable to such Participant upon the settlement of a Performance Award or Performance Unit.

12.2 Terms and Conditions of Deferred Compensation Awards. Deferred Compensation Awards granted pursuant to this Section 12 shall be evidenced by Award Agreements in such form as the Committee shall from time to time establish. No such Deferred Compensation Award or purported Deferred Compensation Award shall be a valid and binding obligation of the Company unless evidenced by a fully executed Award Agreement. Award Agreements evidencing Deferred Compensation Awards may incorporate all or any of the terms of the Plan by reference and shall comply with and be subject to the following terms and conditions:

(a) Vesting Conditions. Deferred Compensation Awards shall not be subject to any vesting conditions.

(b) Terms and Conditions of Stock Units.

(i) Voting Rights, Dividend Equivalent Rights and Distributions. Participants shall have no voting rights with respect to shares of Stock represented by Stock Units until the date of the issuance of such shares (as evidenced by the appropriate entry on the books of the Company or of a duly authorized transfer agent of the Company). However, a Participant shall be entitled to receive Dividend Equivalents with respect to the payment of cash dividends on Stock having a record date prior to the date on which Stock Units held by such Participant are settled. Such Dividend Equivalents shall be paid by crediting the Participant with additional whole and/or fractional Stock Units as of the date of payment of such cash dividends on Stock. The method of determining the number of additional Stock Units to be so credited shall be specified by the Committee and set forth in the Award Agreement. Such additional Stock Units shall be subject to the same terms and conditions and shall be settled in the same manner and at the same time as the Stock Units originally subject to the Stock Unit Award. In the event of a dividend or distribution paid in shares of Stock or any other adjustment made upon a change in the capital structure of the Company as described in Section 4.2, appropriate adjustments shall be made in the Participant’s Stock Unit Award so that it represents the right to receive upon settlement any and all new, substituted or additional securities or other property (other than normal cash dividends) to which the Participant would be entitled by reason of the shares of Stock issuable upon settlement of the Award.

(ii) Settlement of Stock Unit Awards. A Participant electing to receive an Award of Stock Units pursuant to this Section 12, shall specify at the time of such election a settlement date with respect to such Award in accordance with rules established by the Committee. The Company shall issue to the Participant upon the earlier of the settlement date elected by the Participant or the date of the Participant’s Separation from Service, a number of whole shares of Stock equal to the number of whole Stock Units subject to the Stock Unit Award. Such shares of Stock shall be fully vested, and the Participant shall not be required to

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pay any additional consideration (other than applicable tax withholding) to acquire such shares. Any fractional Stock Unit subject to the Stock Unit Award shall be settled by the Company by payment in cash of an amount equal to the Fair Market Value as of the payment date of such fractional share.

(iii) Nontransferability of Stock Unit Awards. Prior to their settlement in accordance with the provision of the Plan, no Stock Unit Award shall be subject in any manner to anticipation, alienation, sale, exchange, transfer, assignment, pledge, encumbrance, or garnishment by creditors of the Participant or the Participant’s beneficiary, except transfer by will or by the laws of descent and distribution. All rights with respect to a Stock Unit Award granted to a Participant hereunder shall be exercisable during his or her lifetime only by such Participant or the Participant’s guardian or legal representative.

13. OTHER STOCK-BASED AWARDS.

In addition to the Awards set forth in Sections 6 through 12 above, the Committee, in its sole discretion, may carry out the purpose of this Plan by awarding Stock-Based Awards as it determines to be in the best interests of the Company and subject to such other terms and conditions as it deems necessary and appropriate.

14. CHANGE IN CONTROL.

14.1 Effect of Change in Control on Options and SARs. In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the “Acquiror”), may, without the consent of any Participant, either assume or continue the Company’s rights and obligations under outstanding Options or SARs or substitute for outstanding Options or SARs substantially equivalent options or SARs covering the Acquiror’s stock. Any Options or SARs which are neither assumed or continued by the Acquiror in connection with the Change in Control nor exercised as of the Change in Control shall, contingent on the Change in Control, become fully vested and exercisable immediately prior to the Change in Control. Options and SARs which are assumed or continued in connection with a Change in Control shall be subject to such additional accelerated vesting and/or exercisability in connection with the Participant’s subsequent termination of Service as the Board may determine.

14.2 Effect of Change in Control on Other Awards. In the event of a Change in Control, the Acquiror may, without the consent of any Participant, either assume or continue the Company’s rights and obligations under outstanding Awards other than Options or SARs or substitute for such Awards substantially equivalent Awards covering the Acquiror’s stock. Any such Awards which are neither assumed or continued by the Acquiror in connection with the Change in Control shall, contingent on the Change in Control, become fully vested. Awards which are assumed or continued in connection with a Change in Control shall be subject to such additional accelerated vesting or lapse of restrictions in connection with the Participant’s subsequent termination of Service as the Board may determine.

14.3 Nonemployee Director Awards. Notwithstanding the foregoing, Nonemployee Director Awards shall be subject to the terms of Section 7, and not this Section 14.

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15. COMPLIANCE WITH SECURITIES LAW.

The grant of Awards and the issuance of shares of Stock pursuant to any Award shall be subject to compliance with all applicable requirements of federal, state and foreign law with respect to such securities and the requirements of any stock exchange or market system upon which the Stock may then be listed. In addition, no Award may be exercised or shares issued pursuant to an Award unless (a) a registration statement under the Securities Act shall at the time of such exercise or issuance be in effect with respect to the shares issuable pursuant to the Award or (b) in the opinion of legal counsel to the Company, the shares issuable pursuant to the Award may be issued in accordance with the terms of an applicable exemption from the registration requirements of the Securities Act. The inability of the Company to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Company’s legal counsel to be necessary to the lawful issuance and sale of any shares hereunder shall relieve the Company of any liability in respect of the failure to issue or sell such shares as to which such requisite authority shall not have been obtained. As a condition to issuance of any Stock, the Company may require the Participant to satisfy any qualifications that may be necessary or appropriate, to evidence compliance with any applicable law or regulation and to make any representation or warranty with respect thereto as may be requested by the Company.

16. TAX WITHHOLDING.

16.1 Tax Withholding in General. The Company shall have the right to deduct from any and all payments made under the Plan, or to require the Participant, through payroll withholding, cash payment or otherwise, including by means of a Cashless Exercise or Net Exercise of an Option, to make adequate provision for, the federal, state, local and foreign taxes, if any, required by law to be withheld by the Participating Company Group with respect to an Award or the shares acquired pursuant thereto. The Company shall have no obligation to deliver shares of Stock, to release shares of Stock from an escrow established pursuant to an Award Agreement, or to make any payment in cash under the Plan until the Participating Company Group’s tax withholding obligations have been satisfied by the Participant.

16.2 Withholding in Shares. The Company shall have the right, but not the obligation, to deduct from the shares of Stock issuable to a Participant upon the exercise or settlement of an Award, or to accept from the Participant the tender of, a number of whole shares of Stock having a Fair Market Value, as determined by the Company, equal to all or any part of the tax withholding obligations of the Participating Company Group. The Fair Market Value of any shares of Stock withheld or tendered to satisfy any such tax withholding obligations shall not exceed the amount determined by the applicable minimum statutory withholding rates.

17. AMENDMENT OR TERMINATION OF PLAN.

The Board or the Committee may amend, suspend or terminate the Plan at any time. However, without the approval of the Company’s shareholders, there shall be (a) no increase in the maximum aggregate number of shares of Stock that may be issued under the Plan (except by operation of the provisions of Section 4.2), (b) no change in the class of persons eligible to receive Incentive Stock Options, and (c) no other amendment of the Plan that would require approval of the Company’s shareholders under any applicable law, regulation or rule.

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Notwithstanding the foregoing, only the Board may amend Section 7. No amendment, suspension or termination of the Plan shall affect any then outstanding Award unless expressly provided by the Board or the Committee. In any event, no amendment, suspension or termination of the Plan may adversely affect any then outstanding Award without the consent of the Participant unless necessary to comply with any applicable law, regulation or rule.

18. MISCELLANEOUS PROVISIONS.

18.1 Repurchase Rights. Shares issued under the Plan may be subject to one or more repurchase options, or other conditions and restrictions as determined by the Committee in its discretion at the time the Award is granted. The Company shall have the right to assign at any time any repurchase right it may have, whether or not such right is then exercisable, to one or more persons as may be selected by the Company. Upon request by the Company, each Participant shall execute any agreement evidencing such transfer restrictions prior to the receipt of shares of Stock hereunder and shall promptly present to the Company any and all certificates representing shares of Stock acquired hereunder for the placement on such certificates of appropriate legends evidencing any such transfer restrictions.

18.2 Provision of Information. Each Participant shall be given access to information concerning the Company equivalent to that information generally made available to the Company’s common shareholders.

18.3 Rights as Employee, Consultant or Director. No person, even though eligible pursuant to Section 5, shall have a right to be selected as a Participant, or, having been so selected, to be selected again as a Participant. Nothing in the Plan or any Award granted under the Plan shall confer on any Participant a right to remain an Employee, Consultant or Director or interfere with or limit in any way any right of a Participating Company to terminate the Participant’s Service at any time. To the extent that an Employee of a Participating Company other than the Company receives an Award under the Plan, that Award shall in no event be understood or interpreted to mean that the Company is the Employee’s employer or that the Employee has an employment relationship with the Company.

18.4 Rights as a Shareholder. A Participant shall have no rights as a shareholder with respect to any shares covered by an Award until the date of the issuance of such shares (as evidenced by the appropriate entry on the books of the Company or of a duly authorized transfer agent of the Company). No adjustment shall be made for dividends, distributions or other rights for which the record date is prior to the date such shares are issued, except as provided in Section 4.2 or another provision of the Plan.

18.5 Fractional Shares. The Company shall not be required to issue fractional shares upon the exercise or settlement of any Award.

18.6 Severability. If any one or more of the provisions (or any part thereof) of this Plan shall be held invalid, illegal or unenforceable in any respect, such provision shall be modified so as to make it valid, legal and enforceable, and the validity, legality and enforceability of the remaining provisions (or any part thereof) of the Plan shall not in any way be affected or impaired thereby.

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18.7 Beneficiary Designation. Subject to local laws and procedures, each Participant may file with the Company a written designation of a beneficiary who is to receive any benefit under the Plan to which the Participant is entitled in the event of such Participant’s death before he or she receives any or all of such benefit. Each designation will revoke all prior designations by the same Participant, shall be in a form prescribed by the Company, and will be effective only when filed by the Participant in writing with the Company during the Participant’s lifetime. If a married Participant designates a beneficiary other than the Participant’s spouse, the effectiveness of such designation may be subject to the consent of the Participant’s spouse. If a Participant dies without an effective designation of a beneficiary who is living at the time of the Participant’s death, the Company will pay any remaining unpaid benefits to the Participant’s legal representative.

18.8 Unfunded Obligation. Participants shall have the status of general unsecured creditors of the Company. Any amounts payable to Participants pursuant to the Plan shall be unfunded and unsecured obligations for all purposes, including, without limitation, Title I of the Employee Retirement Income Security Act of 1974. No Participating Company shall be required to segregate any monies from its general funds, or to create any trusts, or establish any special accounts with respect to such obligations. The Company shall retain at all times beneficial ownership of any investments, including trust investments, which the Company may make to fulfill its payment obligations hereunder. Any investments or the creation or maintenance of any trust or any Participant account shall not create or constitute a trust or fiduciary relationship between the Committee or any Participating Company and a Participant, or otherwise create any vested or beneficial interest in any Participant or the Participant’s creditors in any assets of any Participating Company. The Participants shall have no claim against any Participating Company for any changes in the value of any assets which may be invested or reinvested by the Company with respect to the Plan. Each Participating Company shall be responsible for making benefit payments pursuant to the Plan on behalf of its Participants or for reimbursing the Company for the cost of such payments, as determined by the Company in its sole discretion. In the event the respective Participating Company fails to make such payment or reimbursement, a Participant’s (or other individual’s) sole recourse shall be against the respective Participating Company, and not against the Company. A Participant’s acceptance of an Award pursuant to the Plan shall constitute agreement with this provision.

18.9 Choice of Law. Except to the extent governed by applicable federal law, the validity, interpretation, construction and performance of the Plan and each Award Agreement shall be governed by the laws of the State of California, without regard to its conflict of law rules.

18.10 Section 409A of the Code. Notwithstanding anything to the contrary in the Plan, to the extent any Award payable in connection with a Participant’s Separation from Service constitutes deferred compensation subject to (and not exempt from) Section 409A of the Code and (ii) the Participant is deemed at the time of such separation to be a “specified employee” under Section 409A of the Code and the Treasury regulations thereunder, then payment shall not be made or commence until the earlier of (i) six (6)-months after such Separation from Service or (ii) the date of the Participant’s death following such Separation from Service; provided, however, that such delay shall only be effected to the extent required to avoid adverse tax treatment to the Participant, including (without limitation) the additional twenty percent (20%)

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tax for which the Participant would otherwise be liable under Section 409A(a)(1)(B) of the Code in the absence of such delay. Upon the expiration of the applicable delay period, any payment which would have otherwise been paid during that period (whether in a single sum or in installments) in the absence of this paragraph shall be paid to the Participant or the Participant’s beneficiary in one lump sum on the first business day immediately following such delay.

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PLAN HISTORY AND NOTES TO COMPANY

December 15, 2004 Board adopts Plan with a reserve of 12 million shares.

April 20, 2005 Shareholders approve Plan.

January 1, 2006 Plan Effective Date

February 15, 2006 Change in control provisions are amended

December 20, 2006 Board amends Section 7 containing the terms for automatic awards for Non-Employee Directors, effective January 1, 2007

October 17, 2007 Board amends Section 7 as follows:

Define “Grant Date” for a particular calendar year as the first business day in March of that calendar year. Previously, the grant date for awards in 2006 and 2007 was the first business day in January of that particular calendar year. This amendment becomes effective starting with grants for 2008.

Amend the basis for calculating the per share value of stock option awards, so it is based on the average closing price of Stock during the months of November, December, and January preceding the grant. Previously, the per share value of stock options awards for grants in 2006 and 2007 was based on the average closing price of Stock during the preceding month of November. This amendment becomes effective starting with grants for 2008.

Clarify the language for settling restricted stock awards upon a Nonemployee Director’s retirement from the Board, to indicate that shares credited to a Nonemployee Director’s Restricted Stock Unit account may be settled after a Nonemployee Director ceases to be a member of the Board of Directors following five years of service on the Board.

September 17, 2008 Board amends Section 7 containing the terms for automatic awards for Nonemployee Directors, effective January 1, 2009, to increase the total value of annual equity awards to Nonemployee Directors from $80,000 to $90,000. Of this amount, $45,000 of equity awards shall be Restricted Stock, and the remaining $45,000 shall be a mixture of Options and Restricted Stock Units, consistent with the Plan and with each Nonemployee Director’s election.

Effective January 1, 2009 Plan is amended to comply with the final regulations under Section 409A of the Code

February 18, 2009 Plan is amended to delay grant and pricing of 2009 grants for non-employee directors, to be consistent with 2009 grants to employees.

December 16, 2009 Plan is amended to (1) establish March 10, 2010 as the date of grant of 2010 Plan awards for non-employee directors and calculate the number of shares of restricted stock and restricted stock units (RSUs) to be awarded based upon the average closing price of PG&E Corporation common stock over the five trading days on March 4 through March 10, 2010, and (2) beginning in March 2011, establish that the date of grant of Plan awards for non-employee directors and the price of PG&E Corporation common stock to be used to calculate the number of shares of restricted stock and RSUs to be awarded to non-employee directors be the same as the date of grant and stock price used for the annual LTIP awards for employees.

May 12, 2010 Plan is amended (following approval from the PG&E Corporation Board of Directors and shareholders) to obtain reapproval of the material terms of performance goals, as amended, to have the compensation paid based on these performance goals be eligible for full deductibility under Section 162(m) of the Internal Revenue Code.

December 15, 2010 Plan is amended such that (1) all Nonemployee Director LTIP awards are comprised solely of RSUs granted upon a director’s election to the Board of Directors of PG&E Corporation to serve a one-year term, which vest at the completion of the one-year term of service (unless vesting occurs earlier due to enumerated events and (2) the LTIP prohibits option/SAR cash buyouts or recycling.

EX-10.51

Exhibit 10.51

PG&E CORPORATION

OFFICER SEVERANCE POLICY

(As Amended Effective as of February 15, 2011)

1. Purpose. This is the controlling and definitive statement of the Officer Severance Policy of PG&E Corporation (“Policy”). Since Officers are employed at the will of PG&E Corporation (“Corporation”) or a participating employer (“Employer”), their employment may be terminated at any time, with or without cause. A list of Employers is attached hereto as Appendix A. The Policy, which was first adopted effective November 1, 1998, provides Officers of the Corporation and Employers in Officer Compensation Bands I through V (“Officers”) with severance benefits if their employment is terminated.¹ Severance benefits for officers not covered by this Policy will be provided under policies or programs developed by the appropriate lines of business in consultation with and with the approval by the Senior Human Resources Officer of the Corporation. For the avoidance of doubt, the revisions made to this Policy relating to Code Section 409A (defined below), apply to all Officers including those that may be covered under prior provisions of the Policy as required by Section 6 hereof.

The purpose of the Policy is to attract and retain senior management by defining terms and conditions for severance benefits, to provide severance benefits that are part of a competitive total compensation package, to provide consistent treatment for all terminated officers, and to minimize potential litigation costs associated with Officer termination of employment.

2. Termination of Employment Not Following a Change in Control or Potential Change in Control.

(a) Corporation or Employer’s Obligations. If the Corporation or an Employer exercises its right to terminate an Officer’s employment without cause and such termination does not entitle Officer to payments under Section 3, the Officer shall be given thirty (30) days’ advance written notice or pay in lieu thereof (which shall be paid in a lump sum together with the payment described in Section 2(a)(1) below). Except as provided in Section 2(b) below, in consideration of the Officer’s agreement to the obligations described in Section 2(d) below and to the arbitration provisions described in Section 12 below, the following payments and benefits shall also be provided to Officer following Officer’s separation from service (within the meaning of Code Section 409A):²

(1) A lump sum severance payment equal to: ¹/₁₂ (the sum of the Officer’s annual base compensation and the Officer’s Short-Term Incentive Plan target award at the time

¹ Severance benefits for Officers who are currently covered by an employment agreement will continue to be provided solely under such agreements until their expiration at which time this Policy will become effective for such Officers. If an employee becomes a covered Officer under this Policy as a result of a promotion, if such Officer was then covered by a severance arrangement subject to Section 409A of the Internal Revenue Code of 1986 (“Code Section 409A”), the severance benefits under this Policy provided to such person shall comply with the time and form of payment provisions of such prior severance arrangement, to the extent required by Code Section 409A.

² Any payments made hereunder shall be less applicable taxes.

of his or her termination) times (the number of months that Officer was employed by the Corporation or the Employer (“Severance Multiple”)); provided, however, that the Severance Multiple shall be no less than 6, nor more than 24 for Officers in Officer Bands I, II, III, or more than 18 for Officers in Officer Bands IV or V. Annual base compensation shall mean the Officer’s monthly base pay for the month in which the Officer is given notice of termination, multiplied by 12. The payment described in this Section 2(a)(1) shall be made in a single lump sum as soon as practicable following the date the release of claims described in Section 2(d)(1) becomes effective, provided that payment shall in no event be made later than the 15th day of the third month following the later of the end of the calendar year or the Corporation’s taxable year in which the Officer’s separation from service occurs.

(2) Except as otherwise set forth in the applicable award agreement or as otherwise required by applicable law, the equity-based incentive awards granted to Officer under the Corporation’s Long-Term Incentive Program which have not yet vested as of the date of termination will continue to vest over a period of months equal to the Severance Multiple after the date of termination as if the Officer had remained employed for such period. Except as otherwise set forth in the applicable award agreement, for vested stock options as of the date of termination, the Officer shall have the right to exercise such stock options at any time within their respective terms or within five years after termination, whichever is shorter. Except as otherwise set forth in the applicable award agreement, for stock options that vest during a period of months equal to the Severance Multiple, the Officer shall have the right to exercise such options at any time within five years after termination, subject to the term of the options. Except as otherwise set forth in the applicable award agreement, any unvested equity-based incentive awards remaining at the end of such period shall be forfeited;

(3) For Officers in Officer Bands I, II or III, two thirds of the unvested Company stock units in the Officer’s account in the Corporation’s Deferred Compensation Plan for Officers which were awarded in connection with the Executive Stock Ownership Program requirements (“SISOPs”) shall vest upon the Officer’s termination, and one third shall be forfeited. For Officers in Officer Bands IV and V, one third of any unvested SISOPs shall vest upon the Officer’s termination, and two thirds shall be forfeited. Unvested stock units attributable to SISOPs which become vested under this provision shall be distributed to Officer in accordance with the Deferred Compensation Plan after such stock units vest;

(4) For a period of up to 18 months, the Officer’s COBRA premiums (with such payment subject to taxation if required or advisable to avoid violating the nondiscrimination requirements of Code Section 105(h)), if any;

(5) If Officer is terminated after serving consecutively for six months in a fiscal year, Officer shall be entitled to receive a prorated bonus under any short-term incentive plan in which such Officer participates, at the time such bonus, if any, would otherwise be paid (but in any event no later than the 15th day of the third month following the later of the end of the calendar year or the Corporation’s taxable year in which the Officer’s separation from service occurs or in which the right to such payment otherwise ceases to be subject to a substantial risk of forfeiture for purposes of Code Section 409A);

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(6) To the extent not theretofore paid or provided, the Officer shall be paid or provided with any other amounts or benefits required to be paid or provided or which the Officer is eligible to receive under any plan, contract or agreement of the Corporation or Employer;

(7) Such career transition services as the Corporation’s Senior Human Resources Officer shall determine is appropriate (if any), provided that payment of such services will only be made to the extent the Officer actually incurs an expense and then only to the extent incurred and paid within the time limit set forth in Treasury Regulation Section 1.409A-1(b)(9)(v)(E). Any such services, to the extent they are not exempt under Treasury Regulation Section 1.409A-1(b)(9)(v)(A) or (D), shall be structured to comply with the requirements of Treasuary Regulation Section 1.409A-3(i)(1)(iv) and, if applicable, shall be subject to the six-month delay described in Code Section 409A(a)(2)(B)(i).

(8) All acts required of the Employer under the Policy may be performed by the Corporation for itself and the Employer, and the costs of the Policy may be equitably apportioned by the Administrator among the Corporation and the other Employers. The Corporation shall be responsible for making payments and providing benefits pursuant to this Policy for Officers employed by the Corporation. Whenever the Employer is permitted or required under the terms of the Policy to do or perform any act, matter or thing, it shall be done and performed by any Officer or employee of the Employer who is thereunto duly authorized by the board of directors of the Employer. Each Employer shall be responsible for making payments and providing benefits pursuant to the Policy on behalf of its Officers or for reimbursing the Corporation for the cost of such payments or benefits, as determined by the Corporation in its sole discretion. In the event the respective Employer fails to make such payment or reimbursement, an Officer’s (or other payee’s) sole recourse shall be against the respective Employer, and not against the Corporation;

(b) Remedies. An Officer shall be entitled to recover damages for late or nonpayment of amounts to which the Officer is entitled hereunder. The Officer shall also be entitled to seek specific performance of the obligations and any other applicable equitable or injunctive relief.

(c) Section 2(a) shall not apply in the event that an Officer’s employment is terminated “for cause.” Except as used in Section 3 of this Policy, “for cause” means that the Corporation, in the case of an Officer employed by the Corporation, or Employer in the case of an Officer employed by an Employer, acting in good faith based upon information then known to it, determines that the Officer has engaged in, committed, or is responsible for (1) serious misconduct, gross negligence, theft, or fraud against the Corporation and/or an Employer; (2) refusal or unwillingness to perform his duties; (3) inappropriate conduct in violation of Corporation’s equal employment opportunity policy; (4) conduct which reflects adversely upon, or making any remarks disparaging of, the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries; (5) insubordination; (6) any willful act that is likely to have the effect of injuring the reputation, business, or business relationship of the Corporation or its subsidiaries or affiliates; (7) violation of any fiduciary duty; or (8) breach of any duty of loyalty; or (9) any breach of the restrictive covenants contained in Section 2(d) below. Upon termination “for cause,” the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries shall have no liability to the Officer other than for accrued salary,

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vacation benefits, and any vested rights the Officer may have under the benefit and compensation plans in which the Officer participates and under the general terms and conditions of the applicable plan.

(d) Obligations of Officer.

(1) Release of Claims. There shall be no obligation to commence the payment of the amounts and benefits described in Section 2(a) until the latter of (1) the delivery by Officer to the Corporation a fully executed comprehensive general release of any and all known or unknown claims that he or she may have against the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries and a covenant not to sue in the form prescribed by the Administrator, and (2) the expiration of any revocation period set forth in the release. The Corporation shall promptly furnish such release to Officer in connection with the Officer’s separation from service, and such release must be executed by Officer and become effective during the period set forth in the release as a condition to Officer receiving the payments and benefits described in Section 2(a).

(2) Covenant Not to Compete. (i) During the period of Officer’s employment with the Corporation or its subsidiaries and for a period of months equal to the Severance Multiple thereafter (the “Restricted Period”), Officer shall not, in any county within the State of California or in any city, county or area outside the State of California within the United States or in the countries of Canada or Mexico, directly or indirectly, whether as partner, employee, consultant, creditor, shareholder, or other similar capacity, promote, participate, or engage in any activity or other business competitive with the Corporation’s business or that of any of its subsidiaries or affiliates, without the prior written consent of the Corporation’s Chief Executive Officer. Notwithstanding the foregoing, Officer may have an interest in any public company engaged in a competitive business so long as Officer does not own more than 2 percent of any class of securities of such company, Officer is not employed by and does not consult with, or becomes a director of, or otherwise engage in any activities for, such competing company.

a. The Corporation and its subsidiaries presently conduct their businesses within each county in the State of California and in areas outside California that are located within the United States, and it is anticipated that the Corporation and its subsidiaries will also be conducting business within the countries of Canada and Mexico. Such covenants are necessary and reasonable in order to protect the Corporation and its subsidiaries in the conduct of their businesses. To the extent that the foregoing covenant or any provision of this Section 2(d)(2)a shall be deemed illegal or unenforceable by a court or other tribunal of competent jurisdiction with respect to (i) any geographic area, (ii) any part of the time period covered by such covenant, (iii) any activity or capacity covered by such covenant, or (iv) any other term or provision of such covenant, such determination shall not affect such covenant with respect to any other geographic area, time period, activity or other term or provision covered by or included in such covenant.

(3) Soliciting Customers and Employees. During the Restricted Period, Officer shall not, directly or indirectly, solicit or contact any customer or any prospective customer of the Corporation or its subsidiaries or affiliates for any commercial pursuit that could

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be reasonably construed to be in competition with the Corporation, or induce, or attempt to induce, any employees, agents or consultants of or to the Corporation or any of its subsidiaries or affiliates to do anything from which Officer is restricted by reason of this covenant nor shall Officer, directly or indirectly, offer or aid to others to offer employment to, or interfere or attempt to interfere with any employment, consulting or agency relationship with, any employees, agents or consultants of the Corporation, its subsidiaries and affiliates, who received compensation of $75,000 or more during the preceding six (6) months, to work for any business competitive with any business of the Corporation, its subsidiaries or affiliates.

(4) Confidentiality. Officer shall not at any time (including after termination of employment) divulge to others, use to the detriment of the Corporation or its subsidiaries or affiliates, or use in any business competitive with any business of the Corporation or its subsidiaries or affiliates any trade secret, confidential or privileged information obtained during his employment with the Corporation or its subsidiaries or affiliates, without first obtaining the written consent of the Corporation’s Chief Executive Officer. This paragraph covers but is not limited to discoveries, inventions (except as otherwise provided by California law), improvements, and writings, belonging to or relating to the affairs of the Corporation or of any of its subsidiaries or affiliates, or any marketing systems, customer lists or other marketing data. Officer shall, upon termination of employment for any reason, deliver to the Corporation all data, records and communications, and all drawings, models, prototypes or similar visual or conceptual presentations of any type, and all copies or duplicates thereof, relating to all matters contemplated by this paragraph.

(5) Assistance in Legal Proceedings. During the Restricted Period, Officer shall, upon reasonable notice from the Corporation, furnish information and proper assistance (including testimony and document production) to the Corporation as may be reasonably required by the Corporation in connection with any legal, administrative or regulatory proceeding in which it or any of its subsidiaries or affiliates is, or may become, a party, or in connection with any filing or similar obligation of the Corporation imposed by any taxing, administrative or regulatory authority having jurisdiction, provided, however, that the Corporation shall pay all reasonable expenses incurred by Officer in complying with this paragraph within 60 days after Officer incurs such expenses.

(6) Remedies. Upon Officer’s failure to comply with the provisions of this Section 2(d), the Corporation shall have the right to immediately terminate any unpaid amounts or benefits described in Section 2(a) to Officer. In the event of such termination, the Corporation shall have no further obligations under this Policy and shall be entitled to recover damages. In the event of an Officer’s breach or threatened breach of any of the covenants set forth in this Section 2(d), the Corporation shall also be entitled to specific performance by Officer of any such covenant and any other applicable equitable or injunctive relief.

3. Termination of Employment Following a Change in Control or Potential Change in Control.

(a) If an Executive Officer’s employment by the Corporation or any subsidiary or successor of the Corporation shall be subject to an Involuntary Termination within the Covered

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Period, then the provisions of this Section 3 instead of Section 2 shall govern the obligations of the Corporation as to the payments and benefits it shall provide to the Executive Officer. In the event that Executive Officer’s employment with the Corporation or an employing subsidiary is terminated under circumstances which would not entitle Executive Officer to payments under this Section 3, Executive Officer shall only receive such benefits to which he is entitled under Section 2, if any. In no event shall Executive Officer be entitled to receive termination benefits under both this Section 3 and Section 2.

All the terms used in this Section 3 shall have the following meanings:

(1) “Affiliate” shall mean any entity which owns or controls, is owned or is under common ownership or control with, the Corporation.

(2) “Cause” shall mean (i) the willful and continued failure of the Executive Officer to perform substantially the Executive Officer’s duties with the Corporation or one of its affiliates (other than any such failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive Officer by the Board of Directors or the Chief Executive Officer of the Corporation which specifically identifies the manner in which the Board of Directors or Chief Executive Officer believes that the Executive Officer has not substantially performed the Executive Officer’s duties; or (ii) the willful engaging by the Executive Officer in illegal conduct or gross misconduct which is materially demonstrably injurious to the Corporation.

For purposes of the provision, no act or failure to act, on the part of the Executive Officer, shall be considered “willful” unless it is done, or omitted to be done, by the Executive Officer in bad faith or without reasonable belief that the Executive Officer’s action or omission was in the best interests of the Corporation. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board of Directors or upon the instructions of the Chief Executive Officer or a senior officer of the Corporation or based upon the advice of counsel for the Corporation shall be conclusively presumed to be done, or omitted to be done, by the Executive Officer in good faith and in the best interests of the Corporation. The cessation of employment of the Executive Officer shall not be deemed to be for Cause unless and until there shall have been delivered to the Executive Officer a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters of the entire membership of the Board of Directors at a meeting of the Board of Directors called and held for such purpose (after reasonable notice is provided to the Executive Officer and the Executive Officer is given an opportunity, together with counsel, to be heard before the Board of Directors), finding that, in the good faith opinion of the Board of Directors, the Executive Officer is guilty of the conduct described in subparagraph (i) or (ii) above, and specifying the particulars thereof in detail.

(3) “Change in Control” shall be deemed to have occurred if:

a. any “person” (as such term is used in Sections 13(d) and 14(d)(2) of the Securities Exchange Act of 1934, but excluding any benefit plan for employees or any trustee, agent or other fiduciary for any such plan acting in such person’s capacity as such fiduciary), directly or indirectly, becomes the beneficial owner of securities of the Corporation representing 20 percent or more of the combined voting power of the Corporation’s then outstanding securities;

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b. during any two consecutive years, individuals who at the beginning of such a period constitute the Board of Directors of the Corporation cease for any reason to constitute at least a majority of the Board of Directors of the Corporation, unless the election or the nomination for election by the shareholders of the Corporation, of each new Director was approved by a vote of at least two-thirds (²/₃) of the Directors then still in office who were Directors at the beginning of the period; or

c. any consolidation or merger of the Corporation shall have been consummated other than a merger or consolidation which would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70 percent of the Combined Voting Power of the Corporation, such surviving entity or the parent of such surviving entity outstanding immediately after such merger or consolidation; or

d. the shareholders of the Corporation shall have approved (i) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Corporation; or (ii) any plan or proposal for the liquidation or dissolution of the Corporation.

(4) “Change in Control Date” shall mean the date on which a Change in Control occurs.

(5) “Combined Voting Power” shall mean the combined voting power of the Corporation’s or other relevant entity’s then outstanding voting securities.

(6) “Covered Period” shall mean the period commencing with the Change in Control Date and terminating two (2) years following said commencement; provided, however, that if a Change in Control occurs and Executive Officer’s employment with the Corporation or the employing subsidiary is subject to an Involuntary Termination before the Change in Control Date but on or after a Potential Change in Control Date, and if it is reasonably demonstrated by the Executive Officer that such termination (i) was at the request of a third party who has taken steps reasonably calculated to effect a Change in Control, or (ii) otherwise arose in connection with or in anticipation of a Change in Control, then the Covered Period shall mean, as applied to Executive Officer, the two-year period beginning on the date immediately before the Potential Change in Control Date.

(7) “Disability” shall mean the absence of the Executive Officer from the Executive Officer’s duties with the Corporation or the employing subsidiary on a full-time basis for 180 consecutive business days as a result of incapacity due to physical or mental illness which is determined to be total and permanent by a physician selected by the Corporation or its insurers and acceptable to the Executive Officer or the Executive Officer’s legal representative.

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(8) “Executive Officer” shall mean officers of the Corporation at the level of Senior Vice President and above and the principal executive officer of each Employer.

(9) “Good Reason” shall mean any one or more of the following which takes place within the Covered Period:

a. A material diminution in the Executive Officer’s base compensation;

b. A material diminution in the Executive Officer’s authority, duties, or responsibilities;

c. A material diminution in the authority, duties, or responsibilities of the supervisor to whom the Executive Officer is required to report, including a requirement that the Executive Officer report to a corporate officer or employee instead of reporting directly to the Board of Directors of the Corporation (in the case of an Executive Officer reporting to such Board of Directors);

d. A material diminution in the budget over which the Executive Officer retains authority;

e. A material change in the geographic location at which the Executive Officer must perform the services; or

f. Any other action or inaction that constitutes a material breach by the Corporation of this Policy;

provided, however, that the Executive Officer must provide notice to the Corporation of the existence of the applicable condition described in this Section 3(a)(9) within 90 days of the initial existence of the condition, upon the notice of which the Corporation shall have 30 days during which it may remedy the condition and, if remedied, Good Reason shall not exist.

(10) “Involuntary Termination” shall mean a termination (i) by the Corporation without Cause, or (ii) by Executive Officer following Good Reason; provided, however, the term “Involuntary Termination” shall not include termination of Executive Officer’s employment due to Executive Officer’s death, Disability, or voluntary retirement.

(11) “Potential Change in Control” shall mean the earliest to occur of (i) the date on which the Corporation executes an agreement or letter of intent, where the consummation of the transaction described therein would result in the occurrence of a Change in Control, (ii) the date on which the Board of Directors approves a transaction or series of transactions, the consummation of which would result in a Change in Control, or (iii) the date on which a tender offer for the Corporation’s voting stock is publicly announced, the completion of which would result in a Change in Control; provided, however, that if such Potential Change in Control terminates by its terms, such transaction shall no longer constitute a Potential Change in Control.

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(12) “Potential Change in Control Date” shall mean the date on which a Potential Change in Control occurs.

(13) “Reference Salary” shall mean the greater of (i) the annual rate of Executive Officer’s base salary from the Corporation or the employing subsidiary in effect immediately before the date of Executive Officer’s Involuntary Termination, or (ii) the annual rate of Executive Officer’s base salary from the Corporation or the employing subsidiary in effect immediately before the Change in Control Date.

(14) “Termination Date” shall be the date specified in the written notice of termination of Executive Officer’s employment given by either party in accordance with Section 3(b) of this Policy.

(b) Notice of Termination. During the Covered Period, in the event that the Corporation (including an employing subsidiary) or Executive Officer terminates Executive Officer’s employment with the Corporation or Employer, the party terminating employment shall give written notice of termination to the other party, specifying the Termination Date and the specific termination provision in this Section 3 that is relied upon, if any, and setting forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Executive Officer’s employment under the provision so indicated. The Termination Date shall be determined as follows: (i) if Executive Officer’s employment is terminated for Disability, thirty (30) days after a Notice of Termination is given (provided that Executive Officer shall not have returned to the full-time performance of Executive Officer’s duties during such 30-day period); (ii) if Executive Officer’s employment is terminated by the Corporation in an Involuntary Termination, thirty days after the date the Notice of Termination is received by Executive Officer (provided that the Corporation may provide Officer with pay in lieu of notice, which shall be paid in a lump sum together with the payment described in Section 3(c)(1) below); and (iii) if Executive Officer’s employment is terminated by the Corporation for Cause (as defined in this Section 3), the date specified in the Notice of Termination, provided, that the events or circumstances cited by the Board of Directors as constituting Cause are not cured by Executive Officer during any cure period that may be offered by the Board of Directors. The Date of Termination for a resignation of employment other than for Good Reason shall be the date set forth in the applicable notice, which shall be no earlier than ten (10) days after the date such notice is received by the Corporation, unless waived by the Corporation.

During the Covered Period, a notice of termination given by Executive Officer for Good Reason shall be given within 90 days after occurrence of the event on which Executive Officer bases his notice of termination and shall provide a Termination Date of thirty (30) days after the notice of termination is given to the Corporation (provided that the Corporation may provide Officer with pay in lieu of notice, which shall be paid in a lump sum together with the payment described in Section 3(c)(1) below).

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(c) Corporation’s Obligations. If Executive Officer separates from service due to an Involuntary Termination within the Covered Period, then the Corporation shall provide Executive Officer the following benefits:

(1) The Corporation shall pay to the Executive Officer a lump sum in cash within thirty (30) days after the Executive Officer’s separation from service:

a. the sum of (1) any earned but unpaid base salary through the Termination Date at the rate in effect at the time of the notice of termination to the extent not theretofore paid; (2) the Executive Officer’s target bonus under the Short-Term Incentive Plan of the Corporation, an Affiliate, or a predecessor, for the fiscal year in which the Termination Date occurs (the “Target Bonus”); and (3) any accrued but unpaid vacation pay, in each case to the extent not theretofore paid; and

b. the amount equal to the product of (1) three and (2) the sum of (x) the Reference Salary and (y) the Target Bonus.

(2) The vesting of any benefits conditioned upon continued future employment shall accelerate in full upon the Executive Officer’s separation from service and shall be delivered or paid in accordance with the terms thereof.

(3) Remedies. The Executive Officer shall be entitled to recover damages for late or nonpayment of amounts which the Corporation is obligated to pay hereunder. The Executive Officer shall also be entitled to seek specific performance of the Corporation’s obligations and any other applicable equitable or injunctive relief.

(d) Adjustment for Excise Taxes.

(1) “Best-Net Provision”

Subject to Section 3(d)(2) below, in the event that the payments and other benefits provided for in this Policy or otherwise payable to Executive Officer (i) constitute “parachute payments” within the meaning of Section 280G of the Internal Revenue Code of 1986, as amended (the “Code”) and (ii) would be subject to the excise tax imposed by Section 4999 of the Code, then Executive Officer’s payments and benefits under this Policy or otherwise payable to Executive Officer outside of this Policy shall be either delivered in full (without the Corporation paying any portion of such excise tax), or delivered as to 2.99 times of Executive’s base amount (within the meaning of Section 280G of the Code) so as to result in no portion of such payments and benefits being subject to such excise tax, whichever of the foregoing amounts, taking into account the applicable federal, state and local income taxes and such excise tax, results in the receipt by Executive Officer on an after-tax basis of the greatest amount of payments and benefits, notwithstanding that all or some portion of such payments and benefits may subject to such excise tax. Unless the Corporation and Executive Officer otherwise agree in writing, any determination required under this Section 3(d)(1) shall be made in writing by Deloitte & Touche (the “Accounting Firm”), whose determination shall be conclusive and binding upon Executive Officer and the Corporation for all purposes. For purposes of making the calculations required by this Section 3(d)(1), the Accounting Firm may make reasonable assumptions and approximations concerning applicable taxes and may rely on reasonable, good faith interpretations concerning the application of Section 280G and 4999 of the Code. The Corporation and Executive Officer shall furnish to the Accounting Firm such information and documents as the Accounting Firm may reasonably request in order to make a determination under this Section 3(d)(1).

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Any reduction in payments and/or benefits shall occur in the following order as reasonably determined by the Accounting Firm: (1) reduction of cash payments, (2) reduction of non-cash/non-equity-based payments or benefits, and (3) reduction of vesting acceleration of equity-based awards; provided, however, that any non-taxable payments or benefits shall be reduced last in accordance with the same categorical ordering rule. In the event items described in (1) or (2) are to be reduced, reduction shall occur in reverse chronological order such that the payment or benefit owed on the latest date following the occurrence of the event triggering the excise tax will be the first payment to be reduced (with reductions made pro-rata in the event payments are owed at the same time). In the event that acceleration of vesting of equity-based awards is to be reduced, such acceleration of vesting shall be cancelled in a manner such as to obtain the best economic benefit for the officer (with reductions made pro-rata if economically equivalent), as determined by the Accounting Firm.

(2) Grandfathered Tax Restoration Payment

With respect to officers that were Executive Officers as of February 15, 2011, if any portion of the payments to the Executive Officer under this Section 3 or under any other plan, program, or arrangement maintained by the Corporation (a “Payment”) would be subject to the excise tax levied under the Code, or any interest or penalties are incurred by Executive Officer with respect to such excise tax (such excise tax together with such interest and penalties are referred to herein as the “Excise Tax”), then the Corporation shall make an additional payment to Executive Officer (a “Tax Restoration Payment”) in an amount such that after payment by the Executive Officer of all taxes (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereto) and Excise Tax imposed upon the Tax Restoration Payment, the Executive Officer retains an amount of the Tax Restoration Payment equal to the Excise Tax imposed upon the Payments. The payment of a Tax Restoration Payment under this Section 3 shall not be conditioned upon the Executive Officer’s termination of employment.

All determinations and calculations required to be made under this Section 3(d) shall be made by Deloitte & Touche (the “Accounting Firm”), which shall provide its determination (the “Determination”), together with detailed supporting calculations regarding the amount of any Tax Restoration Payment and any other relevant matter, both to the Corporation and the Executive Officer within five (5) days of the termination of the Executive Officer’s employment, if applicable, or such earlier time as is requested by the Corporation or the Executive Officer (if the Executive Officer reasonably believes that any of the Payments may be subject to Excise Tax). If the Accounting Firm determines that no Excise Tax is payable by the Executive Officer, it shall furnish the Executive Officer with a written statement that such Accounting Firm has concluded that no Excise Tax is payable (including the reasons therefor) and that the Executive Officer has substantial authority not to report any Excise Tax on the Executive Officer’s federal income tax return. If a Tax Restoration Payment is determined to be payable, it shall be paid to the Executive Officer within five (5) days after the Determination is delivered to the Corporation or the Executive Officer. Any determination by the Accounting Firm shall be binding upon the Corporation and the Executive Officer, absent manifest error.

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As a result of uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder, it is possible that Tax Restoration Payments not made by the Corporation should have been made (“Underpayment”) or that Tax Restoration Payments will have been made by the Corporation which should not have been made (“Overpayment”). In either such event, the Accounting Firm shall determine the amount of the Underpayment or Overpayment that has occurred. In the case of an Underpayment, the amount of such Underpayment shall be promptly paid by the Corporation to or for the benefit of the Executive Officer. In the case of an Overpayment, the Executive Officer shall, at the direction and expense of the Corporation, take such steps as are reasonably necessary (including the filing of returns and claims for refund), follow reasonable instructions from, and procedures established by, the Corporation, and otherwise reasonably cooperate with the Corporation to correct such Overpayment, provided, however, that (i) the Executive Officer shall in no event be obligated to return to the Corporation an amount greater than the net after-tax portion of the Overpayment that the Executive Officer has retained or has recovered as a refund from the applicable taxing authorities, and (ii) this provision shall be interpreted in a manner consistent with the intent of the Tax Restoration Payment paragraph above, which is to make the Executive Officer whole, on an after-tax basis, from the application of Excise Tax, it being understood that the correction of an Overpayment may result in the Executive Officer’s repaying to the Corporation an amount that is less than the Overpayment.

All Tax Restoration Payments shall be paid no later than the calendar year next following the calendar year in which the Executive Officer remits the related taxes.

This Section 3(d)(2) will be effective until the third anniversary of the Corporation notifying individuals who are Executive Officers as of February 15, 2011 of the elimination of this Section 3(d)(2) and the application of the potential benefit reductions described in Section 3(d)(1). After such time, such Executive Officers no longer will be eligible for a Tax Restoration Payment pursuant to this Section 3(d)(2) and will instead be subject to Section 3(d)(1).

4. Administration. The Policy shall be administered by the Senior Human Resources Officer of the Corporation (“Administrator”), who shall have the authority to interpret the Policy and make and revise such rules as may be reasonably necessary to administer the Policy. The Administrator shall have the duty and responsibility of maintaining records, making the requisite calculations, securing Officer releases, and disbursing payments hereunder. The Administrator’s interpretations, determinations, rules, and calculations shall be final and binding on all persons and parties concerned.

5. No Mitigation. Payment of the amounts and benefits under Section2(a) and Section 3 (except as otherwise provided in Section 2(a)(5)) shall not be subject to offset, counterclaim, recoupment, defense or other claim, right or action which the Corporation or an Employer may have and shall not be subject to a requirement that Officer mitigate or attempt to mitigate damages resulting from Officer’s termination of employment.

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6. Amendment and Termination. The Corporation, acting through its Nominating and Compensation Committee, reserves the right to amend or terminate the Policy at any time; provided, however, that any amendment which would reduce the aggregate level of benefits, or terminate the Policy, shall not become effective prior to the third anniversary of the Corporation giving notice to Officers of such amendment or termination.

7. Successors. The Corporation will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Corporation expressly to assume and to agree to perform its obligations under this Policy in the same manner and to the same extent that the Corporation would be required to perform such obligations if no such succession had taken place; provided, however, that no such assumption shall relieve the Corporation of its obligations hereunder. As used herein, the “Corporation” shall mean the Corporation as hereinbefore defined and any successor to its business and/or assets as aforesaid which assumes and agrees to perform its obligations by operation or law or otherwise.

This Policy shall inure to the benefit of and be binding upon the Officer (and Officer’s personal representatives and heirs), Corporation and its successors and assigns, and any such successor or assignee shall be deemed substituted for the Corporation under the terms of this Policy for all purposes. As used herein, “successor” and “assignee” shall include any person, firm, corporation or other business entity which at any time, whether by purchase, merger or otherwise, directly or indirectly acquires the stock of the Corporation or to which the Corporation assigns this Policy by operation of law or otherwise. If Officer should die while any amount would still be payable to Officer hereunder if Officer had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with this Policy to Officer’s devisee, legatee or other designee, or if there is no such designee, to Officer’s estate.

8. Nonassignability of Benefits. The payments under this Policy or the right to receive future payments under this Policy may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a person eligible for payments becomes bankrupt, the payments under the Policy of the person affected may be terminated by the Administrator who, in his or her sole discretion, may cause the same to be held if applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that he or she deems appropriate.

9. Nonguarantee of Employment. Officers covered by the Policy are at-will employees, and nothing contained in this Policy shall be construed as a contract of employment between the Officer and the Corporation (or, where applicable, a subsidiary or affiliate of the Corporation), or as a right of the Officer to continued employment, or to remain as an Officer, or as a limitation on the right of the Corporation (or a subsidiary or affiliate of the Corporation) to discharge Officer at any time, with or without cause.

10. Benefits Unfunded and Unsecured. The payments under this Policy are unfunded, and the interest under this Policy of any Officer and such Officer’s right to receive payments under this Policy shall be an unsecured claim against the general assets of the Corporation.

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11. Applicable Law. All questions pertaining to the construction, validity, and effect of the Policy shall be determined in accordance with the laws of the United States and, to the extent not preempted by such laws, by the laws of the state of California.

12. Arbitration. With the exception of any request for specific performance, injunctive or other equitable relief, any dispute or controversy of any kind arising out of or related to this Policy, Officer’s employment with the Corporation (or with the employing subsidiary), the termination thereof or any claims for benefits shall be resolved exclusively by final and binding arbitration in accordance with the Commercial Arbitration Rules of the American Arbitration Association then in effect. Provided, however, that in making their determination, the arbitrators shall be limited to accepting the position of the Officer or the position of the Corporation, as the case may be. The only claims not covered by this Section 12 are claims for benefits under workers’ compensation or unemployment insurance laws; such claims will be resolved under those laws. The place of arbitration shall be San Francisco, California. Parties may be represented by legal counsel at the arbitration but must bear their own fees for such representation. The prevailing party in any dispute or controversy covered by this Section 12, or with respect to any request for specific performance, injunctive or other equitable relief, shall be entitled to recover, in addition to any other available remedies specified in this Policy, all litigation expenses and costs, including any arbitrator or administrative or filing fees and reasonable attorneys’ fees. Such expenses, costs and fees, if payable to Officer, shall be paid within 60 days after they are incurred. Both the Officer and the Corporation specifically waive any right to a jury trial on any dispute or controversy covered by this Section 12. Judgment may be entered on the arbitrators’ award in any court of competent jurisdiction.

13. Reimbursements and In-Kind Benefits. Notwithstanding any other provision of this Policy, all reimbursements and in-kind benefits provided under this Policy shall be made or provided in accordance with the requirements of Code Section 409A, including, where applicable, the requirement that (i) the amount of expenses eligible for reimbursement and the provision of benefits in kind during a calendar year shall not affect the expenses eligible for reimbursement or the provision of in-kind benefits in any other calendar year; (ii) the reimbursement for an eligible expense will be made on or before the last day of the calendar year following the calendar year in which the expense is incurred (or by such earlier time set forth in this Policy); (iii) the right to reimbursement or right to in-kind benefit is not subject to liquidation or exchange for another benefit; and (iv) each reimbursement payment or provision of in-kind benefit shall be one of a series of separate payments (and each shall be construed as a separate identified payment) for purposes of Code Section 409A.

14. Separate Payments. Each payment and benefit under this Policy shall be a “separate payment” for purposes of Code Section 409A.

14

APPENDIX A

PARTICIPATING EMPLOYERS

PG&E Corporation

Pacific Gas and Electric Company

PG&E Corporation Support Services, Inc.

EX-12.1

EXHIBIT 12.1

PACIFIC GAS AND ELECTRIC COMPANY

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Year ended December 31,
	2010		2009		2008		2007		2006
Earnings:
Net income		$1,121		$1,250		$1,199		$1,024		$985
Adjustments for income or loss from equity investees of less than 100% owned affiliates and the Company’s equity in undistributed income (losses) of less than 50% owned affiliates		-		-		-		-		-
Income taxes provision		574		482		488		571		602
Fixed charges		799		817		860		889		801
Total Earnings		$2,494		$2,549		$2,547		$2,484		$2,388
Fixed Charges:
Interest on short-term borrowings and long-term debt, net		731		754		$794		$834		$770
Interest on capital leases		18		19		22		23		11
AFUDC debt		50		44		44		32		20
Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned trust		-		-		-		-		-
Total Fixed Charges		$799		$817		$860		$889		$801
Ratios of Earnings to Fixed Charges		3.12		3.12		2.96		2.79		2.98

Note:

For the purpose of computing Pacific Gas and Electric Company’s ratios of earnings to fixed charges, “earnings” represent net income adjusted for the income or loss from equity investees of less than 100% owned affiliates, equity in undistributed income or losses of less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). “Fixed charges” include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, AFUDC debt, and earnings required to cover the preferred stock dividend requirements and preferred security distribution requirements of majority-owned trust. Fixed charges exclude interest on tax liabilities.

EX-12.2

EXHIBIT 12.2

PACIFIC GAS AND ELECTRIC COMPANY

COMPUTATION OF RATIOS OF EARNINGS TO COMBINED

FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

	Year ended December 31,
Earnings:	2010		2009		2008		2007		2006
Net income		$1,121		$1,250		$1,199		$1,024		$985
Adjustments for income or loss from equity investees of less than 100% owned affiliates and the Company’s equity in undistributed income (losses) of less than 50% owned affiliates		-		-		-		-		-
Income taxes provision		574		482		488		571		602
Fixed charges		799		817		860		889		801
Total Earnings		$2,494		$2,549		$2,547		$2,484		$2,388
Fixed Charges:
Interest on short-term borrowings and long-term debt, net		$731		$754		$794		$834		$770
Interest on capital leases		18		19		22		23		11
AFUDC debt		50		44		44		32		20
Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned trust		-		-		-		-
Total Fixed Charges		$799		$817		$860		$889		$801
Preferred Stock Dividends:
Tax deductible dividends		9		9		9		9		12
Pre-tax earnings required to cover non-tax deductible preferred stock dividend requirements		7		7		7		8		3
Total Preferred Stock Dividends		16		16		16		17		15
Total Combined Fixed Charges and Preferred Stock Dividends		$815		$833		$876		$906		$816
Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends		3.06		3.06		2.91		2.74		2.93

Note:

For the purpose of computing Pacific Gas and Electric Company’s ratios of earnings to combined fixed charges and preferred stock dividends, “earnings” represent net income adjusted for the income or loss from equity investees of less than 100% owned affiliates, equity in undistributed income or losses of less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). “Fixed charges” include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, AFUDC debt, and earnings required to cover the preferred stock dividend requirements and preferred security distribution requirements of majority-owned trust. “Preferred stock dividends” represent tax deductible dividends and pre-tax earnings that are required to pay the dividends on outstanding preferred securities. Fixed charges exclude interest on tax liabilities.

EX-12.3

EXHIBIT 12.3

PG&E CORPORATION

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Year Ended December 31,
	2010			2009			2008			2007			2006
Earnings:
Incoming from continuing operations		$1,113			$1,234			$1,198			$1,020			$1,005
Income taxes provision		547			460			425			539			554
Fixed charges		850			861			907			937			845
Pre-tax earnings required to cover the preferred stock dividend of consolidated subsidiaries		(16	)		(16	)		(16	)		(17	)		(15)
Total Earnings		$2,494			$2,539			$2,514			$2,479			$2,389
Fixed Charges:
Interest and amortization of premiums, discounts and capitalized expenses related to short-term borrowings and long-term debt, net		$766			$798			$825			$865			$799
Interest on capital leases		18			19			22			23			11
AFUDC debt		50			44			44			32			20
Pre-tax earnings required to cover the preferred stock dividend of consolidated subsidiaries		16			16			16			17			15
Total Fixed Charges		$850			$877			$907			$937			$845
Ratios of Earnings to Fixed Charges		2.93			2.90			2.77			2.65			2.83

Note:

For the purpose of computing PG&E Corporation’s ratios of earnings to fixed charges, “earnings” represent income from continuing operations adjusted for income taxes, fixed charges (excluding capitalized interest), and pre-tax earnings required to cover the preferred stock dividend of consolidated subsidiaries. “Fixed charges” include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, AFUDC debt, and earnings required to cover preferred stock dividends of consolidated subsidiaries. Fixed charges exclude interest on tax liabilities.

EX-13

Exhibit 13

Contents

Financial Highlights		2
Selected Financial Data		3
Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Overview	4
	Cautionary Language Regarding Forward Looking Statements	7
	Results of Operations	9
	Liquidity and Financial Resources	16
	Contractual Commitments	22
	Contingencies	23
	Capital Expenditures	23
	Off-Balance Sheet Arrangements	24
	Regulatory Matters	24
	Pending Investigations	28
	Environmental Matters	30
	Legal Matters	32
	Risk Management Activities	33
	Critical Accounting Policies	34
	Risk Factors	38
PG&E Corporation
	Consolidated Statements of Income	49
	Consolidated Balance Sheets	50
	Consolidated Statements of Cash Flows	52
	Consolidated Statements of Equity	53
Pacific Gas and Electric Company
	Consolidated Statements of Income	54
	Consolidated Balance Sheets	55
	Consolidated Statements of Cash Flows	57
	Consolidated Statements of Shareholders’ Equity	58
Notes to the Consolidated Financial Statements
	Note 1: Organization and Basis of Presentation	59
	Note 2: Summary of Significant Accounting Policies	59
	Note 3: Regulatory Assets, Liabilities, and Balancing Accounts	66
	Note 4: Debt	70
	Note 5: Energy Recovery Bonds	73
	Note 6: Common Stock and Share-Based Compensation	74
	Note 7: Preferred Stock	78
	Note 8: Earnings Per Share	79
	Note 9: Income Taxes	81
	Note 10: Derivatives and Hedging Activities	83
	Note 11: Fair Value Measurements	87
	Note 12: Employee Benefit Plans	93
	Note 13: Resolution of Remaining Chapter 11 Disputed Claims	102
	Note 14: Related Party Agreements and Transactions	103
	Note 15: Commitments and Contingencies	103
Quarterly Consolidated Financial Data (Unaudited)		111
Management’s Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm

1

FINANCIAL HIGHLIGHTS ⁽¹⁾

PG&E Corporation

(unaudited, in millions, except share and per share amounts)	2010			2009
Operating Revenues	$	13,841		$	13,399
Income Available for Common Shareholders
Earnings from operations (2)		1,331			1,223
Items impacting comparability (3)		(232	)		(3	)
Reported consolidated Income Available for Common Shareholders		1,099			1,220
Income Per Common Share, Diluted
Earnings from operations (2)		3.42			3.21
Items impacting comparability (3)		(0.60	)		(0.01	)
Reported consolidated Net Earnings Per Common Share, Diluted		2.82			3.20
Dividends Declared Per Common Share		1.82			1.68
Total Assets at December 31,	$	46,025		$	42,945
Number of common shares outstanding at December 31,		395,227,205			371,272,457

⁽¹⁾ This is a combined annual report of PG&E Corporation and Pacific Gas and Electric Company (“Utility”). PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries.

⁽²⁾ “Earnings from operations” is not calculated in accordance with the accounting principles generally accepted in the United States of America (“GAAP”). It should not be considered an alternative to income available for common shareholders calculated in accordance with GAAP. Earnings from operations reflects PG&E Corporation’s consolidated income available for common shareholders, but excludes items that management believes do not reflect the normal course of operations, in order to provide a measure that allows investors to compare the core underlying financial performance of the business from one period to another.

⁽³⁾ “Items impacting comparability” represent items that management believes do not reflect the normal course of operations. PG&E Corporation’s earnings from operations for 2010 exclude $168 million of costs, after tax, ($ 0.43) per common share, relating to the September 9, 2010 natural gas transmission pipeline accident in San Bruno, California. This amount primarily included a provision for estimated third-party claims for personal injury and property damage claims, and other damage claims, as well as costs incurred to provide immediate support to the San Bruno community, re-inspect the Utility’s natural gas transmission lines, and perform other activities following the accident. Additionally, during 2010 the Utility spent $45 million, after-tax, ($0.12) per common share, to support a state-wide ballot initiative and recorded a charge of $19 million, ($0.05) per common share, triggered by the elimination of the tax deductibility of Medicare Part D federal subsidies.

PG&E Corporation’s earnings from operations for 2009 excludes $66 million of income, after tax, $0.18 per common share, for the interest and state tax benefit associated with a federal tax refund for 1998 and 1999; $28 million of income, after tax, $0.07 per common share, representing the recovery of costs previously incurred by the Utility in connection with its hydroelectric generation facilities; $59 million of costs, after tax, ($0.16) per common share, incurred by the Utility to perform accelerated system-wide natural gas integrity surveys and associated remedial work; and $38 million of severance costs, after-tax, ($0.10) per common share, related to the elimination of approximately 2% of the Utility’s workforce.

2

SELECTED FINANCIAL DATA

(in millions, except per share amounts)	2010			2009		2008 (1)		2007		2006
PG&E Corporation For the Year
Operating revenues	$	13,841		$	13,399	$	14,628	$	13,237	$	12,539
Operating income		2,308			2,299		2,261		2,114		2,108
Income from continuing operations		1,113			1,234		1,198		1,020		1,005
Earnings per common share from continuing operations, basic		2.86			3.25		3.23		2.79		2.78
Earnings per common share from continuing operations, diluted		2.82	(2)		3.20		3.22		2.78		2.76
Dividends declared per common share (3)		1.82			1.68		1.56		1.44		1.32
At Year-End
Common stock price per share	$	47.84		$	44.65	$	38.71	$	43.09	$	47.33
Total assets		46,025			42,945		40,860		36,632		34,803
Long-term debt (excluding current portion)		10,906			10,381		9,321		8,171		6,697
Capital lease obligations (excluding current portion) (4)		248			282		316		346		376
Energy recovery bonds (excluding current portion) (5)		423			827		1,213		1,582		1,936
Pacific Gas and Electric Company For the Year
Operating revenues	$	13,840		$	13,399	$	14,628	$	13,238	$	12,539
Operating income		2,314			2,302		2,266		2,125		2,115
Income available for common stock		1,107			1,236		1,185		1,010		971
At Year-End
Total assets		45,679			42,709		40,537		36,310		34,371
Long-term debt (excluding current portion)		10,557			10,033		9,041		7,891		6,697
Capital lease obligations (excluding current portion) (4)		248			282		316		346		376
Energy recovery bonds (excluding current portion) (5)		423			827		1,213		1,582		1,936

⁽¹⁾ Matters relating to discontinued operations are discussed in the section entitled “Results of Operations” within “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Note 9 of the Notes to the Consolidated Financial Statements.

⁽²⁾ See the discussion entitled “Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for 2010” in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

⁽³⁾ Information about the frequency and amount of dividends and restrictions on the payment of dividends is set forth in the section entitled “Liquidity and Financial Resources – Dividends” within “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 6 of the Notes to the Consolidated Financial Statements.

⁽⁴⁾ The capital lease obligations amounts are included in noncurrent liabilities – other in the PG&E Corporation’s and the Utility’s Consolidated Balance Sheets.

⁽⁵⁾ See Note 5 of the Notes to the Consolidated Financial Statements.

3

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

OVERVIEW

PG&E Corporation, incorporated in California in 1995, 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 generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility served approximately 5.2 million electric distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2010.

The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). In addition, the Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility’s electric and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and over the rates and terms and conditions of service governing the Utility on its interstate natural gas transportation contracts. Before setting rates, the CPUC and the FERC determine the annual amount of revenue (“revenue requirements”) that the Utility is authorized to collect from its customers to recover its reasonable operating and capital costs of providing utility services. The primary rate-setting proceeding at the CPUC is the general rate case (“GRC”) which occurs approximately every three years. The primary rate-setting proceeding at the FERC is the electric transmission owner (“TO”) rate case which occurs every year.

The authorized revenue requirements also provide the Utility an opportunity to earn a return on “rate base,” the Utility’s net investment in facilities, equipment, and other property used or useful in providing utility service to its customers. The CPUC determines the capital structure the Utility must maintain (i.e., the relative weightings of common equity, preferred equity, and debt) when financing its rate base and authorizes the Utility to earn a specific rate of return on each capital component, including a rate of return on equity (“ROE”). The CPUC has set the Utility’s authorized ROE through 2011 at 11.35%. A change in ROE 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 more 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 ability to recover the revenue requirements authorized by the CPUC in a GRC does not depend on the volume of the Utility’s sales of electricity and natural gas services. This “decoupling” of revenues and sales eliminates volatility in the revenues earned by the Utility due to fluctuations in customer demand. However, fluctuations in operating and maintenance costs may impact the Utility’s ability to earn its authorized rate of return. Generally, the Utility’s recovery of its FERC-authorized revenue requirements can vary with the volume of electricity sales. The Utility’s ability to recover a portion of its CPUC-authorized revenue requirements for its natural gas transportation and storage services also depends on the volume of natural gas transported and the extent to which the Utility provides firm transmission services.

The Utility collects additional revenue requirements to recover certain costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; to fund public purpose, demand response, and customer energy efficiency programs; and to recover certain capital expenditures. The Utility’s ability to recover these costs is not dependent on the volume of the Utility’s sales. Therefore, although the timing and amount of these costs can impact the Utility’s revenue, these costs generally do not impact earnings. The Utility’s revenues and earnings also are affected by incentive ratemaking mechanisms that adjust rates depending on the extent the Utility meets certain performance criteria, such as customer energy efficiency goals.

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

4

Key Factors Affecting Results of Operations and Financial Condition

PG&E Corporation’s and the Utility’s results of operations and financial condition depend primarily on whether the Utility is able to operate its business within authorized revenue requirements, recover its authorized costs timely, and earn its authorized rate of return. A number of factors have had, or are expected to have, a significant impact on PG&E Corporation’s and the Utility’s results of operations and financial condition, including:

• The Outcome of Pending Investigations of Natural Gas Explosions and Fires. On September 9, 2010, a Utility-owned natural gas pipeline ruptured in a residential area located in the City of San Bruno, California (“San Bruno accident”) which resulted in the deaths of eight people, injuries to numerous individuals, and extensive property damage. Both the National Transportation Safety Board (“NTSB”) and the CPUC are investigating the San Bruno accident. A cause of the pipeline rupture has not yet been determined. The investigations will examine various aspects of the operating, maintenance and emergency response practices used in the Utility’s natural gas operations as well as the Utility’s record-keeping and compliance with pipeline safety regulations. In addition, various civil lawsuits have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility related to the San Bruno accident. (See “Legal Matters” below.) During 2010, the Utility recorded a total of $283 million of costs associated with the San Bruno accident, including a provision of $220 million for estimated third party claims and $63 million of costs incurred to provide immediate support to the San Bruno community, re-inspect the Utility’s natural gas transmission lines, and to perform other activities following the accident. The Utility estimates that it may incur as much as $400 million for third-party claims. (See Note 15 of the Notes to the Consolidated Financial Statements.) The total amount of third-party liability claims will depend on the final determination of the causes for the pipeline rupture and responsibility for the personal injuries and property damages and the number and nature of third-party claims. Although PG&E Corporation and the Utility currently consider it likely that most of the costs the Utility incurs for third-party claims will ultimately be covered by its liability insurance, no amounts for insurance recoveries have been recorded as of December 31, 2010. The CPUC also has initiated an investigation of a natural gas explosion and fire that occurred on December 24, 2008 in a house located in Rancho Cordova, California (“Rancho Cordova accident”). The Utility expects that it will continue to incur unforecasted costs related to its natural gas operations as the investigations of the San Bruno and Rancho Cordova accidents progress, including costs to conduct an exhaustive review of records related to the Utility’s natural gas transmission system and to perform pressure tests on portions of its natural gas transmission system. Further, if state or federal legislation that is being considered to address natural gas transmission operations and maintenance is enacted, the Utility may incur additional costs to comply with new statutory requirements. The Utility may not be able to recover these additional unforecasted costs through rates. (See “Operating and Maintenance Expenses” and “Pending Investigations” below.) Finally, PG&E Corporation’s and the Utility’s financial condition, results of operation, and cash flows may be affected by the amount of penalties and fines, if any, that may be imposed on the Utility related to these matters.

• The Outcome of Ratemaking Proceedings. There are several rate cases that are currently pending at the CPUC and the FERC, the outcome of which will determine the majority of the Utility’s base revenue requirements for 2011 and several years thereafter. These proceedings are discussed below under “Regulatory Matters.” From time to time, the Utility also requests that the CPUC authorize additional base revenue requirements for specific capital expenditure projects such as new power plants. (See “Capital Expenditures” below.) The outcome of these proceedings can be affected by many factors, including general economic conditions, the level of customer rates, and political and regulatory policies. (See “Risk Factors” below.)

• The Ability of the Utility to Control Operating Costs and Capital Expenditures. The Utility’s revenue requirements are generally set by the CPUC and the FERC at a level to allow the Utility the opportunity to recover its forecasted operating expenses, to recover depreciation, tax, and interest expenses associated with forecasted capital expenditures, and to earn a ROE. Actual costs may differ from forecasts, or the Utility may incur significant unanticipated costs, such as costs related to storms, outages, catastrophic events, or costs incurred to comply with regulatory orders or legislation. Differences in the amount or timing of forecasted or authorized and actual costs can affect the Utility’s ability to earn its authorized rate of return and the amount of PG&E Corporation’s income available for common shareholders. (See “Capital Expenditures” below.) To the extent the Utility is unable to conclude that costs are probable of recovery through rates, the Utility will incur a charge to income. (See “Critical Accounting Policies” below.)

5

• Authorized Capital Structure, Rate of Return, and Financing. The Utility’s CPUC-authorized capital structure for its electric and natural gas distribution and electric generation rate base consisting of 52% common equity and 48% debt and preferred stock will remain in effect through 2012. The Utility’s CPUC-authorized ROE of 11.35% will remain in effect through 2011 but is subject to change based on an annual adjustment mechanism described below under “Liquidity and Financial Resources.” The timing and amount of the Utility’s future debt financing will depend on the timing and amount of capital expenditures and other factors. PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure. PG&E Corporation may issue debt or equity to fund these equity contributions. (See “Liquidity and Financial Resources” below.)

Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for 2010

PG&E Corporation’s income available for common shareholders decreased by $121 million, or 10%, from $1,220 million in 2009 to $1,099 million in 2010. The following table is a summary reconciliation of the key changes in income available for common shareholders and earnings per common share for the year ended December 31, 2010:

	Earnings			Earnings Per Common Share (Diluted)
Income Available for Common Shareholders – 2009	$	1,220		$	3.20
San Bruno accident (1)		(168	)		(0.43	)
Tax refund (2)		(66	)		(0.18	)
Statewide ballot initiative (3)		(45	)		(0.12	)
Recovery of hydroelectric generation-related costs (4)		(28	)		(0.07	)
Federal healthcare law (5)		(19	)		(0.05	)
Rate base earnings (6)		88			0.23
Accelerated work on gas system (7)		59			0.16
Severance costs (8)		38			0.10
Other (9)		20			0.05
Increase in shares outstanding (10)		—			(0.07	)
Income Available for Common Shareholders – 2010	$	1,099		$	2.82
(1)  During 2010, the Utility recorded charges of $168 million, after-tax, for the San Bruno accident. These charges primarily included a provision for estimated third-party claims for personal injury and property damage claims, and other damage claims, as well as, costs incurred to provide immediate support to the San Bruno community, re-inspect the Utility’s natural gas transmission lines, and to perform other activities following the accident. (2)  During 2009, PG&E Corporation recognized $66 million for the interest benefit associated with a federal tax refund. (3)  During 2010, the Utility contributed $45 million to support Proposition 16 – The Taxpayers Right to Vote Act. (4)  During 2009, the Utility recognized income of $28 million, after-tax, for the recovery of costs previously incurred in connection with its hydroelectric generation facilities. (5)  During 2010, the Utility recorded a charge of $19 million triggered by the elimination of the tax deductibility of Medicare Part D federal subsidies. (6)  During 2010, the Utility recognized earnings of $88 million, after-tax, attributable to the ROE on higher authorized capital investments. (7)  During 2009, the Utility incurred $59 million, after-tax, for costs to perform accelerated system-wide natural gas integrity surveys and associated remedial work. (8)  During 2009, the Utility accrued $38 million, after-tax, of severance costs related to the elimination of approximately 2% of its workforce. (9)  During 2010, the Utility incurred lower expenses for nuclear refueling outages, uncollectible customer accounts and disability costs, partially offset by a charge for SmartMeterTM related capital costs and higher storm and outage expenses. (10) Represents the impact of a lower number of shares outstanding in 2009 compared to 2010; this has no dollar impact on earnings.

6

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures; estimated environmental remediation, tax, and other liabilities; estimates and assumptions used in PG&E Corporation’s and the Utility’s critical accounting policies; the anticipated outcome of various regulatory, governmental, and legal proceedings; estimated losses and insurance recoveries associated with the San Bruno accident; estimated future cash flows; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim,” “may,” “might,” “should,” “would,” “could,” “goal,” “potential,” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

• the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within authorized levels and timely recover its costs through rates;

• the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigations by the NTSB and CPUC into the cause of the San Bruno accident and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory, the CPUC investigation of the Rancho Cordova accident, whether the Utility incurs civil or criminal penalties as a result of these proceedings whether the Utility is required to incur additional costs for third-party liability claims or to comply with regulatory or legislative mandates which costs the Utility is unable to recover through rates or insurance, and whether the Utility incurs third-party liabilities or other costs in connection with service disruptions that may occur as the Utility complies with regulatory orders to decrease pressure in its natural gas transmission system;

• reputational harm that PG&E Corporation and the Utility may suffer depending on the outcome of the various investigations, including those by the NTSB and the CPUC, the outcome of civil litigation, and the extent to which civil or criminal proceedings may be pursued by regulatory or governmental agencies;

• the adequacy and price of electricity and natural gas supplies the extent to which the Utility can manage and respond to the volatility of electricity and natural gas prices, and the ability of the Utility and its counterparties to post or return collateral;

• explosions, fires, accidents, mechanical breakdowns, the disruption of information technology and systems, human errors, and similar events that may occur while operating and maintaining an electric and natural gas system in a large service territory with varying geographic conditions that can cause unplanned outages, reduce generating output, damage the Utility’s assets or operations, subject the Utility to third-party claims for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utility;

• the impact of storms, earthquakes, floods, drought, wildfires, disease, and similar natural disasters, or acts of terrorism or vandalism, that affect customer demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies;

• the potential impacts of climate change on the Utility’s electricity and natural gas businesses;

• changes in customer demand for electricity (“load”) and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology that include the development of alternative technologies that enable customers to increase their reliance on self-generation, or other reasons;

• the occurrence of unplanned outages at the Utility’s two nuclear generating units at Diablo Canyon Power Plant (“Diablo Canyon”), the availability of nuclear fuel, the outcome of the Utility’s application to renew the operating licenses for Diablo Canyon, and potential changes in laws or regulations promulgated by the NRC or environmental agencies with respect to the storage of spent nuclear fuel, security, safety, cooling water intake, or other matters associated with the operations at Diablo Canyon;

• whether the Utility earns incentive revenues or incurs obligations under incentive ratemaking mechanisms, such as the CPUC’s incentive ratemaking mechanism relating to energy savings achieved through implementation of the utilities’ customer energy efficiency programs;

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• the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies;

• whether the Utility can successfully complete its program to install advanced meters for its electric and natural gas customers, allay customer concerns about the new metering technology, and integrate the new meters with its customer billing and other systems while also implementing the system design changes necessary to accommodate retail electric rates based on dynamic pricing (i.e., electric rates that can vary with the customer’s time of use and are more closely aligned with wholesale electricity prices) by the CPUC’s due dates;

• how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company and the extent to which the interpretation or enforcement of these conditions has a material impact on PG&E Corporation;

• the extent to which PG&E Corporation or the Utility incurs costs in connection with third-party claims or litigation, including those arising from the San Bruno accident, that are not recoverable through insurance, rates, or from other third parties;

• the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;

• the impact of environmental laws and regulations addressing the reduction of carbon dioxide and other greenhouse gases (“GHG”), water, the remediation of hazardous waste, and other matters, and whether the Utility is able to recover the costs of compliance with such laws, including the cost of emission allowances and offsets that the Utility may incur under federal or state cap and trade regulations;

• the loss of customers due to various forms of bypass and competition, including municipalization of the Utility’s electric distribution facilities, increasing levels of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which permits cities and counties to purchase and sell electricity for their local residents and businesses; and

• the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations, such as The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (the “Tax Relief Act”).

For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see the discussion in the section entitled “Risk Factors” below. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

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RESULTS OF OPERATIONS

The table below details certain items from the accompanying Consolidated Statements of Income for 2010, 2009, and 2008:

	Year ended December 31,
(in millions)	2010			2009			2008
Utility
Electric operating revenues	$	10,644		$	10,257		$	10,738
Natural gas operating revenues		3,196			3,142			3,890
Total operating revenues		13,840			13,399			14,628
Cost of electricity		3,898			3,711			4,425
Cost of natural gas		1,291			1,291			2,090
Operating and maintenance		4,432			4,343			4,197
Depreciation, amortization, and decommissioning		1,905			1,752			1,650
Total operating expenses		11,526			11,097			12,362
Operating income		2,314			2,302			2,266
Interest income		9			33			91
Interest expense		(650	)		(662	)		(698	)
Other income, net		22			59			28
Income before income taxes		1,695			1,732			1,687
Income tax provision		574			482			488
Net income		1,121			1,250			1,199
Preferred stock dividend requirement		14			14			14
Income Available for Common Stock	$	1,107		$	1,236		$	1,185
PG&E Corporation, Eliminations, and Other(1)
Operating revenues	$	1		$	—		$	—
Operating expenses		7			3			5
Operating loss		(6	)		(3	)		(5	)
Interest income		—			—			3
Interest expense		(34	)		(43	)		(30	)
Other income (expense), net		5			8			(32	)
Loss before income taxes		(35	)		(38	)		(64	)
Income tax benefit		(27	)		(22	)		(63	)
Loss from continuing operations		(8	)		(16	)		(1	)
Discontinued operations(2)		—			—			154
Net income (loss)	$	(8	)	$	(16	)	$	153
Consolidated Total
Operating revenues	$	13,841		$	13,399		$	14,628
Operating expenses		11,533			11,100			12,367
Operating income		2,308			2,299			2,261
Interest income		9			33			94
Interest expense		(684	)		(705	)		(728	)
Other income (expense), net		27			67			(4	)
Income before income taxes		1,660			1,694			1,623
Income tax provision		547			460			425
Income from continuing operations		1,113			1,234			1,198
Discontinued operations(2)		—			—			154
Net income		1,113			1,234			1,352
Preferred stock dividend requirement of subsidiary		14			14			14
Income Available for Common Shareholders	$	1,099		$	1,220		$	1,338

⁽¹⁾ PG&E Corporation eliminates all intercompany transactions in consolidation.

⁽²⁾ Discontinued operations reflect items related to PG&E Corporation’s former subsidiary, National Energy & Gas Transmission, Inc. See “PG&E Corporation, Eliminations, and Other” section in “Results of Operations” for further discussion.

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Utility

The following presents the Utility’s operating results for 2010, 2009, and 2008.

Electric Operating Revenues

The Utility’s electric operating revenues consist of amounts charged to customers for electricity generation and for electric transmission and distribution services, as well as amounts charged to customers to recover the cost of electric procurement, public purpose, energy efficiency, and demand response programs. The Utility provides electricity to residential, industrial, agricultural, and small and large commercial customers through its own generation facilities and through power purchase agreements with third parties. In addition, a portion of the Utility’s customers’ load is satisfied by electricity provided under long-term contracts between the California Department of Water Resources (“DWR”) and various power suppliers. The commodity costs and associated revenues to recover the costs allocated to the Utility by the DWR are not included in the Consolidated Statements of Income.

The following table provides a summary of the Utility’s total electric operating revenues:

	2010		2009		2008
(in millions)
Revenues excluding pass-through costs	$	6,123	$	5,905	$	5,562
Revenues for recovery of passed-through costs		4,521		4,352		5,176
Total electric operating revenues	$	10,644	$	10,257	$	10,738

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $387 million, or 4%, in 2010 compared to 2009. Costs that are passed through to customers and do not impact net income increased by $169 million, primarily due to increases in the cost of electricity procurement partially offset by decreases in the cost of public purpose programs. (See “Cost of Electricity” below.) Electric operating revenues, excluding costs passed through to customers, increased by $218 million. This was primarily due to increases in authorized base revenues.

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, decreased by $481 million, or 4%, in 2009 compared to 2008. Costs that are passed through to customers and do not impact net income decreased by $824 million, primarily due to decreases in the costs of public purpose programs and electricity procurement. (See “Cost of Electricity” below.) Electric operating revenues, excluding costs passed through to customers, increased by $343 million. This was primarily due to $344 million of increases in authorized base revenues composed of an attrition increase (as approved in the last GRC covering 2007 through 2010) and increases in revenues to recover capital expenditures that have separately authorized by the CPUC.

The Utility’s future electric operating revenues will be impacted by final authorization by the CPUC in the 2011 GRC and by the FERC in the TO rate cases. (See “Regulatory Matters” below.) The Utility also expects to continue to collect revenue requirements related to CPUC-approved capital expenditures outside the GRC, including capital expenditures for the SmartMeter^TM advanced metering project. Revenues will increase to the extent that the CPUC approves the Utility’s proposals for other capital projects. Finally, the Utility may earn incentive revenues under the existing energy efficiency ratemaking mechanism. (See “Regulatory Matters” below.)

Cost of Electricity

The Utility’s mix of resources used to serve customers is determined by the availability of the Utility’s own electricity generation, the amount of electricity supplied under the DWR’s contracts allocated to the Utility’s customers, and the cost-effectiveness of other third-party sources of electricity. The Utility’s cost of electricity includes costs to purchase power from third parties, certain transmission costs, the cost of fuel used in its own generation facilities, and the cost of fuel supplied to other facilities under tolling agreements. The Utility’s cost of electricity also includes realized gains and losses on price risk management activities. (See Notes 10 and 11 of the Notes to the Consolidated Financial Statements.) The Utility’s cost of electricity is passed through to customers. The Utility’s cost of electricity excludes non-fuel costs associated with operating the Utility’s own generation facilities, which are included in operating and maintenance expense in the Consolidated Statements of Income.

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The following table provides a summary of the Utility’s cost of electricity and the total amount and average cost of purchased power:

	2010		2009		2008
(in millions)
Cost of purchased power	$	3,647	$	3,508	$	4,261
Fuel used in own generation facilities		251		203		164
Total cost of electricity	$	3,898	$	3,711	$	4,425
Average cost of purchased power per kWh (1)	$	0.081	$	0.082	$	0.089
Total purchased power (in kWh)		44,837		42,767		47,668
(1)     Kilowatt-hour

The Utility’s total cost of electricity increased by $187 million, or 5%, in 2010 compared to 2009. This was caused by an increase in purchased power and an increase in the cost of fuel used in the Utility’s own generation facilities as the Utility increased its non-nuclear generation to replace power that had previously been provided under a DWR contract that expired at the end of 2009 (costs associated with power provided to the Utility’s customers under DWR contracts are not included in the Utility’s cost of purchased power). The volume of purchased power is driven by the availability of the Utility’s own electricity generation and the cost-effectiveness of each source of electricity.

The Utility’s total cost of electricity decreased by $714 million, or 16%, in 2009 compared to 2008, primarily due to an 8% decrease in the average price of purchased power and a 10% decrease in the total volume of purchased power. The decrease in the average cost of purchased power was primarily driven by lower market prices for electricity and gas. The decrease in the volume of purchased power primarily resulted from an increase in the amount of power generated by facilities owned by the Utility such as the new Gateway Generating Station. The Utility’s mix of resources is determined by the availability of the Utility’s own electricity generation and the cost-effectiveness of each source of electricity.

Various factors will affect the Utility’s future cost of electricity, including the market prices for electricity and natural gas, the level of hydroelectric and nuclear power that the Utility produces, changes in customer demand, and the amount and timing of power purchases needed to replace power previously supplied under the DWR contracts as those contracts expire or are terminated, replaced, or renegotiated. Additionally, the cost of electricity is expected to continue reflecting the higher cost of procuring renewable energy as the Utility increases the amount of its renewable energy deliveries to comply with current and future California law and regulatory requirements. The Utility expects that it will be able to continue passing through the costs of its renewable energy purchase commitments to customers. (See “Environmental Matters – Renewable Energy Resources” and “Risk Factors” below.)

The Utility’s future cost of electricity also will be affected by federal or state legislation or rules that may be adopted to regulate GHG emissions. (See “Environmental Matters – Climate Change” and “Risk Factors” below.)

Natural Gas Operating Revenues

The Utility sells natural gas and natural gas transportation services. The Utility’s transportation services are provided by a transmission system and a distribution system. The Utility transports gas throughout its service territory, both by using its distribution system to deliver to end-use customers, as well as to large end-use customers who are connected directly to the transmission system. In addition, the Utility delivers natural gas to off-system markets, primarily in southern California.

The Utility’s natural gas customers consist of two categories: residential and smaller commercial customers known as “core” customers and industrial and larger commercial customers known as “non-core” customers. The Utility provides natural gas transportation services to all core and non-core customers connected to the Utility’s system in its service territory. Core customers can purchase natural gas from either the Utility or alternate energy service providers. The Utility does not procure natural gas for non-core customers. When the Utility provides both transportation and natural gas supply, the Utility refers to the combined service as “bundled natural gas service.” In 2010, core customers represented over 99% of the Utility’s total customers and 39% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total customers and 61% of its total natural gas deliveries.

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The following table provides a summary of the Utility’s natural gas operating revenues:

	2010		2009		2008
(in millions)
Revenues excluding pass-through costs	$	1,703	$	1,667	$	1,616
Revenues for recovery of passed-through costs		1,493		1,475		2,274
Total natural gas operating revenues	$	3,196	$	3,142	$	3,890

The Utility’s natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $54 million, or 2%, in 2010 compared to 2009. This reflects an $18 million increase in the costs which are passed through to customers and do not impact net income, primarily due to an increase in the cost of public purpose programs. Natural gas operating revenues, excluding costs passed through to customers, increased by $36 million, primarily due to an increase in authorized base revenue, partially offset by a decrease in natural gas storage revenues. (The Utility’s storage facilities were at capacity throughout the year and less gas was transported from storage due to the milder weather that prevailed. As result, the Utility was unable to accept more gas for storage.)

The Utility’s total natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, decreased by $748 million, or 19%, in 2009 compared to 2008. This reflects a $799 million decrease in the total cost of natural gas which is passed through to customers and generally does not impact net income. (See “Cost of Natural Gas” below.) Natural gas operating revenues, excluding costs passed through to customers, increased by $51 million primarily due to an increase in authorized base revenues.

The Utility’s future natural gas operating revenues will be impacted by final authorization by the CPUC in the 2011 GRC and the 2011 Gas Transmission and Storage rate case. Finally, the Utility may earn incentive revenues under the existing energy efficiency ratemaking mechanism. (See “Regulatory Matters” below.)

Cost of Natural Gas

The Utility’s cost of natural gas includes the purchase costs of natural gas, transportation costs on interstate pipelines, and gas storage costs but excludes the transportation costs on intrastate pipelines for core and non-core customers, which are included in operating and maintenance expense in the Consolidated Statements of Income. The Utility’s cost of natural gas also includes realized gains and losses on price risk management activities. (See Notes 10 and 11 of the Notes to the Consolidated Financial Statements.)

The following table provides a summary of the Utility’s cost of natural gas:

	2010		2009		2008
(in millions)
Cost of natural gas sold	$	1,119	$	1,130	$	1,955
Transportation cost of natural gas sold		172		161		135
Total cost of natural gas	$	1,291	$	1,291	$	2,090
Average cost per Mcf (1) of natural gas sold	$	4.69	$	4.47	$	7.43
Total natural gas sold (in millions of Mcf)		249		253		263
(1)     One thousand cubic feet

The Utility’s total cost of natural gas decreased by less than $1 million in 2010 compared to 2009. The Utility received $49 million in the first quarter of 2010 to be refunded to customers as part of a litigation settlement arising from the manipulation of the natural gas market by third parties during 1999 through 2002. The decrease resulting from the settlement was partially offset by an increase in transportation costs primarily due to attrition adjustments and an increase in procurement costs due to increases in the average market price of natural gas purchased.

The Utility’s total cost of natural gas decreased by $799 million, or 38%, in 2009 compared to 2008, primarily due to decreases in the average market price of natural gas.

The Utility’s future cost of natural gas will be affected by the market price of natural gas and changes in customer demand. In addition, the Utility’s future cost of natural gas may be affected by federal or state legislation or rules to regulate the GHG emissions from the Utility’s natural gas transportation and distribution facilities and from natural gas consumed by the Utility’s customers.

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Operating and Maintenance

Operating and maintenance expenses consist mainly of the Utility’s costs to operate and maintain its electricity and natural gas facilities, customer billing and service expenses, the cost of public purpose programs, and administrative and general expenses. Operating and maintenance expenses are influenced by wage inflation; changes in liabilities for employee benefits; property taxes; the timing and length of Diablo Canyon refueling outages; the occurrence of storms, wildfires, and other events causing outages and damages in the Utility’s service territory; environmental remediation costs; legal costs; changes in the accrual for legal matters; materials costs; the level of uncollectible customer accounts; and various other factors. Although some of the Utility’s operating and maintenance expenses, like the cost of public purpose programs, are passed through to customers and generally do not impact net income, many other expenses are less predictable and less controllable and do impact net income. The Utility’s ability to earn its authorized rate of return depends in large part on the success of its ability to manage these expenses and to achieve operational and cost efficiencies.

The Utility’s operating and maintenance expenses (including costs passed through to customers) increased by $89 million, or 2%, in 2010 compared to 2009. During 2010, the change in pass-through operating and maintenance costs as compared to 2009 was immaterial. The increase in operating and maintenance expenses was primarily due to $283 million of costs associated with the San Bruno accident. This amount includes a provision of $220 million for estimated third-party claims, including personal injury and property damage claims, damage to infrastructure, and other damage claims. (See Note 15 of the Notes to the Consolidated Financial Statements.) The additional $63 million of costs associated with the San Bruno accident were incurred to provide immediate support to the San Bruno community, re-inspect the Utility’s natural gas transmission lines, and perform other activities following the accident. Additionally, operating and maintenance expenses increased due to a $36 million provision that was recorded for SmartMeter^TM related capital costs that are forecasted to exceed the CPUC-authorized amount for recovery. (See “Regulatory Matters – Deployment of SmartMeter^TM Technology” below.) These increases were partially offset by decreases of approximately $139 million in labor costs and other costs as compared to 2009 when costs were incurred in connection with an additional scheduled refueling outage at Diablo Canyon and accelerated natural gas leak surveys (and associated remedial work), $67 million in severance costs as compared to the same period in 2009 when charges were incurred related to the reduction of approximately 2% of the Utility’s workforce, and $21 million in uncollectible customer accounts as a result of customer outreach and increased collection efforts.

The Utility’s operating and maintenance expenses (including costs passed through to customers) increased by $146 million, or 3%, in 2009 compared to 2008. During 2009, the pass-through costs of public purpose programs decreased by $111 million as compared to the level of program spending in 2008. Excluding costs passed through to customers, operating and maintenance expenses increased by $257 million, primarily due to approximately $100 million of costs to perform accelerated natural gas leak surveys and associated remedial work, $67 million of employee severance costs incurred due to the reduction of approximately 2% of the Utility’s workforce, $42 million of costs related to the SmartMeter^TM advanced metering project, and $35 million of costs for the second refueling outage at Diablo Canyon. The remaining increase consists primarily of employee wage and benefit costs that were partially offset by lower storm-related costs as compared to 2008 when costs were incurred in connection with the January 2008 winter storm.

The Utility currently estimates that it may incur as much as $180 million for third-party claims related to the San Bruno accident in future years, in addition to the $220 million provision recorded in 2010. (See Note 15 of the Notes to the Consolidated Financial Statements.) The Utility also expects to continue to incur other costs related to the San Bruno accident, including costs to comply with CPUC orders and NTSB recommendations that have been issued in connection with the investigation of the San Bruno accident, such as costs to perform an exhaustive review of records related to the Utility’s natural gas transmission system and to perform pressure tests on portions of its natural gas transmission system. The Utility currently estimates that these costs could range from approximately $200 million to $300 million for 2011. These estimates could change depending on a number of factors, including the outcome of the NTSB and CPUC investigations, the outcome of the “safety phase” of the Utility’s 2011 Gas Transmission and Storage Rate Case, and the outcome of future rule-making, ratemaking, or investigatory proceedings at the CPUC. (See “Regulatory Matters” and “Pending Investigations” below.) In addition, current estimates could be affected by state and federal legislative requirements that may be adopted to establish operating practice standards for natural gas transmission operations and safety, to require the use of certain types of inspection methods and equipment, and to require the installations of certain types of valves. If this or similar legislation is enacted, the Utility may incur unforecasted costs to comply with new statutory requirements. PG&E Corporation and the Utility are uncertain whether all or a portion of the costs the Utility may incur to respond to orders, recommendations, or new legislative requirements, would be recoverable through rates and the timing of any such recovery. Finally, if the CPUC institutes one or more formal investigations related to the San Bruno accident or the Utility’s natural gas operating and maintenance practices in addition to the formal investigation of the Rancho Cordova accident, the CPUC may impose fines or penalties, which may be material, on the Utility if the CPUC determines that the Utility violated laws, rules, regulations or orders.

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Depreciation, Amortization, and Decommissioning

The Utility’s depreciation and amortization expense consists of depreciation and amortization on plant and regulatory assets, and decommissioning expenses associated with fossil and nuclear decommissioning. The Utility’s depreciation, amortization, and decommissioning expenses increased by $153 million, or 9%, in 2010 compared to 2009, primarily due to an increase in authorized capital additions.

The Utility’s depreciation, amortization, and decommissioning expenses increased by $102 million, or 6%, in 2009 compared to 2008, primarily due to an increase in authorized capital additions and depreciation rate changes.

The Utility’s depreciation expense for future periods is expected to increase as a result of an overall increase in capital expenditures and implementation of depreciation rates authorized by the CPUC. Depreciation expenses in subsequent years will be determined based on rates set by the CPUC in the 2011 GRC and the 2011 Gas Transmission and Storage rate case, and by the FERC in future TO rate cases.

Interest Income

The Utility’s interest income decreased by $24 million, or 73%, in 2010 as compared to 2009, primarily due to lower interest rates affecting various regulatory balancing accounts and fluctuations in those accounts. In addition, interest income decreased as compared to 2009 when the Utility received interest income on previously incurred costs related to the proposed divestiture of its hydroelectric generation facilities.

The Utility’s interest income decreased by $58 million, or 64%, in 2009 compared to 2008, primarily due to lower interest rates affecting various regulatory balancing accounts and regulatory assets and lower balances in those accounts. In addition, interest income decreased due to lower interest rates earned on funds held in escrow pending the disposition of disputed claims that had been made in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”). (See Note 13 of the Notes to the Consolidated Financial Statements.) These decreases were partially offset by an increase in interest income for the recovery of interest on previously incurred costs related to the Utility’s hydroelectric generation facilities.

The Utility’s interest income in future periods will be primarily affected by changes in the balance of funds held in escrow pending resolution of the Chapter 11 disputed claims, changes in regulatory balancing accounts, and changes in interest rates.

Interest Expense

The Utility’s interest expense decreased by $12 million, or 2%, in 2010 as compared to 2009. This decrease was primarily attributable to decreases in the outstanding balances of the liability for Chapter 11 disputed claims, energy recovery bonds (“ERBs”), and various regulatory balancing accounts and to lower interest rates on short-term debt. The decrease was partially offset by an increase in outstanding senior notes. (See Note 4 of the Notes to the Consolidated Financial Statements.)

The Utility’s interest expense decreased by $36 million, or 5%, in 2009 as compared to 2008. This was primarily attributable to lower interest rates and outstanding balances on liabilities that the Utility incurs interest expense on (such as the liability for Chapter 11 disputed claims and various regulatory balancing accounts). This decrease was partially offset by higher outstanding balances for long-term debt due to timing of senior note issuances.

The Utility’s interest expense in future periods will be impacted by changes in interest rates, changes in the liability for Chapter 11 disputed claims, changes in regulatory balancing accounts and regulatory assets, and changes in the amount of debt outstanding as long-term debt matures and additional long-term debt is issued. (See “Liquidity and Financial Resources” below.)

Other Income, Net

The Utility’s other income, net decreased by $37 million, or 63%, in 2010 compared to 2009. The decrease was primarily due to a $45 million increase in other expenses as a result of costs the Utility incurred to support a California ballot initiative that appeared on the June 2010 ballot, which are not recoverable in rates. This expense was partially offset by a $15 million increase in allowance for equity funds used during construction due to higher average balances of construction work in progress.

The Utility’s other income, net increased by $31 million, or 111%, in 2009 compared to 2008, when the Utility incurred costs to oppose a California ballot initiative related to renewable energy and to oppose the City of San Francisco’s municipalization efforts.

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Income Tax Provision

The Utility’s income tax provision increased by $92 million, or 19%, in 2010 compared to 2009. The effective tax rates were 34% and 28% for 2010 and 2009, respectively. The effective tax rate for 2010 increased as compared to the same period in 2009 when the Utility recognized state tax benefits arising from tax accounting method changes and benefits of various audit settlements at higher levels than 2010 settlements. The effective tax rate also increased due to the reversal of a deferred tax asset in the first quarter of 2010 that had previously been recorded to reflect the future tax benefits attributable to the Medicare Part D subsidy after 2012, which was eliminated as part of the federal healthcare legislation passed during March 2010. (See Note 9 of the Notes to the Consolidated Financial Statements.)

The Utility’s income tax provision decreased by $6 million, or 1%, in 2009 compared to 2008. The effective tax rates were 28% and 29% for 2009 and 2008, respectively. The lower effective tax rate for 2009 was primarily due to the recognition of California tax and related interest benefits attributable to the settlement of various federal tax matters. (See Note 9 of the Notes to the Consolidated Financial Statements.)

The differences between the Utility’s income taxes and amounts calculated by applying the federal statutory rate to income before income tax expense for continuing operations for 2010, 2009, and 2008 were as follows:

	2010			2009			2008
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit)		1.0			1.4			3.3
Effect of regulatory treatment of fixed asset differences		(3.0	)		(2.6	)		(3.1	)
Tax credits		(0.4	)		(0.5	)		(0.5	)
IRS audit settlements		(0.2	)		(4.2	)		(4.1	)
Other, net		1.5			(1.3	)		(1.7	)
Effective tax rate		33.9	%		27.8	%		28.9	%

PG&E Corporation, Eliminations, and Other

Operating Revenues and Expenses

PG&E Corporation’s revenues consist mainly of billings to its affiliates for services rendered, all of which are eliminated in consolidation. PG&E Corporation’s operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation’s operating expenses are allocated to affiliates. These allocations are made without mark-up and are eliminated in consolidation. PG&E Corporation’s interest expense relates to PG&E Corporation’s 9.5% Convertible Subordinated Notes, which were no longer outstanding at December 31, 2010, and 5.8% Senior Notes, and is not allocated to affiliates.

There were no material changes to PG&E Corporation’s operating revenues and expenses in 2010 compared to 2009 and 2009 compared to 2008.

Other Income (Expense), Net

PG&E Corporation’s other income, net decreased by $3 million, or 38%, in 2010 compared to 2009, primarily due to smaller investment-related gains in the rabbi trusts established in connection with the non-qualified deferred compensation plans. The investment-related gains resulted in a net increase to other income of $40 million, or 125%, in 2009 compared to 2008.

Income Tax Benefit

PG&E Corporation’s income tax benefit increased by $5 million, or 23%, in 2010 primarily due to a write-off of a deferred tax asset in 2009, with no comparable amount in the current year.

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PG&E Corporation’s income tax benefit decreased by $41 million, or 65%, in 2009 compared to 2008, primarily due to a settlement of federal tax audits for the tax years 2001 to 2004 in 2008 with no similar adjustment in 2009.

Discontinued Operations

In the fourth quarter of 2008, PG&E Corporation reached a settlement of federal tax audits for tax years 2001 through 2004 and recognized after-tax income of $257 million, including $154 million related to losses incurred and synthetic fuel tax credits claimed by PG&E Corporation’s former subsidiary, National Energy & Gas Transmission, Inc. (“NEGT”). As a result, PG&E Corporation recorded $154 million in income from discontinued operations in 2008. (See Note 9 of the Notes to the Consolidated Financial Statements.) No similar amount was recognized in 2010 or 2009.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations depends on the levels of its operating cash flows and access to the capital and credit markets. The levels of the Utility’s operating cash and short-term debt fluctuate as a result of seasonal load and natural gas, volatility in energy commodity costs, collateral requirements related to price risk management activity, the timing and amount of tax payments or refunds, and the timing and effect of regulatory decisions and financings, among other factors. The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure. The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs. The CPUC 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 Utility has short-term borrowing authority of $4.0 billion, including $500 million that is restricted to certain contingencies.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund Utility equity contributions as needed for the Utility to maintain its CPUC-authorized capital structure, fund tax equity investments, and pay dividends primarily depends on the level of cash distributions received from the Utility and PG&E Corporation’s access to the capital and credit markets.

The following table summarizes PG&E Corporation’s and the Utility’s cash positions:

	December 31,
(in millions)	2010		2009
PG&E Corporation	$	240	$	193
Utility		51		334
Total consolidated cash and cash equivalents		291		527
Utility restricted cash		563		633
	$	854	$	1,160

Restricted cash primarily consists of cash held in escrow pending the resolution of the remaining disputed claims filed in the Utility’s reorganization proceeding under Chapter 11. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds.

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s revolving credit facilities at December 31, 2010:

(in millions)	Termination Date	Facility Limit			Letters of Credit Outstanding		Cash Borrowings		Commercial Paper Backup		Availability
PG&E Corporation	February 2012	$	187	(1)	$	—	$	—		N/A	$	187
Utility	February 2012		1,940	(2)		329		—	$	603		1,008
Utility	February 2012		750	(3)		N/A		—		—		750
Total credit facilities		$	2,877		$	329	$	—	$	603	$	1,945

⁽¹⁾ Includes an $87 million sublimit for letters of credit and a $100 million commitment for “swingline” loans, defined as loans that are made available on a same-day basis and are repayable in full within 30 days.

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⁽²⁾ Includes a $921 million sublimit for letters of credit and a $200 million commitment for swingline loans.

⁽³⁾ Includes a $75 million commitment for swingline loans.

For the year ended December 31, 2010, the average outstanding cash borrowings and commercial paper balance were $33 million and $655 million, respectively.

PG&E Corporation’s and the Utility’s credit agreements contain covenants that are usual and customary for credit facilities of this type, including covenants limiting liens, mergers, substantial asset sales, and other fundamental changes. Both the $750 million and the $1.9 billion revolving credit facilities require that the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter. In addition, the $187 million revolving credit facility agreement requires that PG&E Corporation must own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility.

At December 31, 2010, PG&E Corporation and the Utility were in compliance with all covenants under each of the revolving credit facilities listed in the table above.

2010 Financings

PG&E Corporation

On November 4, 2010, PG&E Corporation entered into an Equity Distribution Agreement pursuant to which PG&E Corporation’s sales agents may offer and sell, from time to time, PG&E Corporation common stock having an aggregate gross offering price of up to $400 million. Sales of the shares are made by means of ordinary brokers’ transactions on the New York Stock Exchange, or in such other transactions as agreed upon by PG&E Corporation and the sales agents and in conformance with applicable securities laws. As of December 31, 2010, PG&E Corporation had issued 2,357,796 shares of common stock pursuant to the Equity Distribution Agreement for cash proceeds of $110 million, net of fees and commissions paid of $1 million.

In addition, during 2010, PG&E Corporation issued 5,105,505 shares of common stock upon the exercise of employee stock options and under its 401(k) plan and Dividend Reinvestment and Stock Purchase Plan, generating $192 million of cash. PG&E Corporation issued 16,370,779 shares of common stock upon conversion of the $247 million principal amount of PG&E Corporation’s Convertible Subordinated Notes at a conversion price of $15.09 per share between June 23 and June 29, 2010. These notes were no longer outstanding at December 31, 2010, and the conversion had no impact on cash.

Utility

The following table summarizes debt issuances in 2010. (See Note 4 of the Notes to the Consolidated Financial Statements.)

(in millions)	Issue Date		Amount
Senior Notes
5.8%, due 2037		April 1	$	250
3.5%, due 2020		September 15		550
Floating rate, due 2011		October 12		250
3.5%, due 2020		November 18		250
5.4%, due 2040		November 18		250
Total senior notes				1,550
Pollution control bonds
Series 2010E, 2.25%, due 2026 (1)		April 8		50
Total debt issuances in 2010			$	1,600

⁽¹⁾ These bonds bear interest at 2.25% per year through April 1, 2012, are subject to mandatory tender on April 2, 2012, and may be remarketed in a fixed or variable rate mode.

The net proceeds from the issuance of Utility senior notes in 2010 were used to repay outstanding commercial paper and for general corporate purposes. The net proceeds from the issuance of the pollution control bonds by the California Infrastructure and Economic Development Bank for the benefit of the Utility were used to fund capital investments and general working capital needs.

The Utility also received a contribution of $190 million of cash from PG&E Corporation during 2010 to ensure that the Utility had adequate capital to fund its capital expenditures and to maintain the 52% common equity ratio authorized by the CPUC.

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Future Financing Needs

The amount and timing of the Utility’s future financings will depend on various factors, including:

• the amount of cash internally generated through normal business operations;

• the timing and amount of forecasted capital expenditures authorized in GRC or TO rate cases or whether the CPUC approves the Utility’s requests for specific capital projects outside of the GRC (discussed below under “Capital Expenditures”);

• the timing of the resolution of the Chapter 11 disputed claims and the amount of interest on these claims that the Utility will be required to pay;

• the timing and amount of payments made to third parties in connection with the San Bruno accident, and the timing and amount of related insurance recoveries;

• the reduction in future tax payments as a result of legislation in December 2010 that allows for bonus depreciation on qualified property (discussed below under “Utility – Operating Activities”); and

• the conditions in the capital markets, and other factors. (See Notes 13 and 15 of the Notes to the Consolidated Financial Statements.)

PG&E Corporation may issue debt or equity in the future to fund equity contributions to the Utility and to fund tax equity investments to the extent that internally generated funds are not sufficient. PG&E Corporation’s financing needs depend primarily on the timing and amount of contributions made to the Utility to maintain the Utility’s 52% common equity ratio authorized by the CPUC. Further, at December 31, 2010, PG&E Corporation made certain tax equity investments (see “PG&E Corporation” below) and may fund similar investments in the future, resulting in additional financing needs.

PG&E Corporation and the Utility have had continued access to the capital markets on reasonable terms and continue to believe that the Utility’s cash flows from operations, existing sources of liquidity, and future financings will provide adequate resources to fund operating activities, meet anticipated obligations, make payments to third parties related to the San Bruno accident, and finance future capital expenditures and investments.

Dividends

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

• Comparability: Pay a dividend competitive with the securities of comparable companies based on payout ratio (the proportion of earnings paid out as dividends) and, with respect to PG&E Corporation, yield (i.e., dividend divided by share price);

• Flexibility: Allow sufficient cash to pay a dividend and to fund investments while avoiding having to issue new equity unless PG&E Corporation’s or the Utility’s capital expenditure requirements are growing rapidly and PG&E Corporation or the Utility can issue equity at reasonable cost and terms; and

• Sustainability: Avoid reduction or suspension of the dividend despite fluctuations in financial performance except in extreme and unforeseen circumstances.

The Boards of Directors of PG&E Corporation and the Utility have each adopted a target dividend payout ratio range of 50% to 70% of earnings. Dividends paid by PG&E Corporation and the Utility are expected to remain in the lower end of the target payout ratio range so that more internal funds are readily available to support each company’s capital investment needs. Each Board of Directors retains authority to change the respective common stock dividend policy and dividend payout ratio at any time, especially if unexpected events occur that would change its view as to the prudent level of cash conservation. No dividend is payable unless and until declared by the applicable Board of Directors.

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In addition, the CPUC requires that the PG&E Corporation Board of Directors give first priority to the Utility’s capital requirements, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner, in setting the amount of dividends.

The Boards of Directors must also consider the CPUC requirement that the Utility maintain, on average, its CPUC-authorized capital structure including a 52% equity component.

The following table summarizes PG&E Corporation’s and the Utility’s dividends paid:

(in millions)	2010		2009		2008
PG&E Corporation:
Common stock dividends paid	$	662	$	590	$	546
Common stock dividends reinvested in Dividend Reinvestment and Stock Purchase Plan		18		17		20
Utility:
Common stock dividends paid	$	716	$	624	$	568
Preferred stock dividends paid		14		14		14

On December 15, 2010, the Board of Directors of PG&E Corporation declared a quarterly dividend of $0.455 per share, totaling $183 million, which was paid on January 15, 2011 to shareholders of record on December 31, 2010. On February 16, 2011, the Board of Directors of PG&E Corporation declared a dividend of $0.455 per share, payable on April 15, 2011, to shareholders of record on March 31, 2011.

On December 15, 2010, the Board of Directors of the Utility declared a cash dividend on its outstanding series of preferred stock totaling $4 million that was paid on February 15, 2011 to preferred shareholders of record on January 31, 2011. On February 16, 2011, the Board of Directors of the Utility declared a cash dividend on its outstanding series of preferred stock, payable on May 15, 2011, to shareholders of record on April 29, 2011.

PG&E Corporation and the Utility each have revolving credit facilities that require the company to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%. This covenant, along with the CPUC’s requirement for the Utility to maintain the 52% equity component of its capital structure, are considered to be restrictions on the payment of dividends. Based on the calculation of these ratios for each company, no amount of PG&E Corporation’s retained earnings and $5.3 billion of the Utility’s retained earnings were restricted at December 31, 2010.

In addition, the Utility was required to maintain at least $9.7 billion of its net assets as equity in order to maintain the capital structure of at least 52% equity at December 31, 2010. As a result, $9.7 billion of the Utility’s net assets are restricted and may not be transferred to PG&E Corporation in the form of cash dividends.

Utility

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash.

The Utility’s cash flows from operating activities for 2010, 2009, and 2008 were as follows:

(in millions)	2010			2009			2008
Net income	$	1,121		$	1,250		$	1,199
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		2,116			1,927			1,838
Allowance for equity funds used during construction		(110	)		(94	)		(70	)
Deferred income taxes and tax credits, net		762			787			593
Other		46			(27	)		(6	)
Effect of changes in operating assets and liabilities:
Accounts receivable		(105	)		157			(83	)
Inventories		(43	)		109			(59	)
Accounts payable		109			(33	)		(137	)
Disputed claims and customer refunds		—			(700	)		—
Income taxes receivable/payable		(58	)		21			43
Other current assets		(7	)		122			(187	)
Other current liabilities		130			183			60
Regulatory assets, liabilities, and balancing accounts, net		(394	)		(516	)		(374	)
Other changes in noncurrent assets and liabilities		(331	)		(282	)		(51	)
Net cash provided by operating activities	$	3,236		$	2,904		$	2,766

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During 2010, net cash provided by operating activities increased $332 million compared to 2009. This increase reflects the Utility’s payment to the California Power Exchange (“PX”) in 2009, partially offset by net tax refunds that the Utility received in 2009 that were higher than the amount received in 2010. (The Utility’s payment to the PX decreased the Utility’s liability for the remaining net disputed claims that had been made in the Utility’s Chapter 11 proceeding. See Note 13 of the Notes to the Consolidated Financial Statements.) The remaining changes in cash flows from operating activities consisted of fluctuations in activities within the normal course of business such as collateral, power purchases, and customer billings.

During 2009, net cash provided by operating activities increased $138 million compared to 2008. This increase reflects significantly lower commodity market prices in 2009 compared to 2008, which resulted in fewer cash outflows related to the timing of inventory and procurement activities. These net inflows were partially offset by the payment to the PX.

On December 17, 2010, the Tax Relief Act was signed into law, allowing qualified property placed into service after September 8, 2010, and before January 1, 2012, to be eligible for 100% bonus depreciation for tax purposes and qualified property placed into service in 2012 to be eligible for 50% bonus depreciation for tax purposes. (See Note 9 of the Notes to the Consolidated Financial Statements.) As a result, the Utility expects to make no federal tax payment in 2011. A reduction in the 2012 federal tax payment is expected, however the amount cannot be reasonably estimated at this time. (See “Regulatory Matters – CPUC Resolution Regarding the Tax Relief Act” below.)

Additionally, there is uncertainty around the timing and amount of payments to be made to third parties in connection with the San Bruno accident, the timing and amount of related insurance recoveries, any penalties that may be assessed, costs associated with related investigations, and costs associated with changes to pipeline management and operations.

Investing Activities

The Utility’s investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash used in investing activities depends primarily upon the amount and timing of the Utility’s capital expenditures, which can be affected by many factors, including the timing of regulatory approvals and the occurrence of storms and other events causing outages or damages to the Utility’s infrastructure. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. (See Note 11 of the Notes to the Consolidated Financial Statements.)

The Utility’s cash flows from investing activities for 2010, 2009, and 2008 were as follows:

(in millions)	2010			2009			2008
Capital expenditures	$	(3,802	)	$	(3,958	)	$	(3,628	)
Decrease in restricted cash		66			666			36
Proceeds from sales and maturities of nuclear decommissioning trust investments		1,405			1,351			1,635
Purchases of nuclear decommissioning trust investments		(1,456	)		(1,414	)		(1,684	)
Other		19			11			1
Net cash used in investing activities	$	(3,768	)	$	(3,344	)	$	(3,640	)

Net cash used in investing activities increased by $424 million in 2010 compared to 2009, primarily due to the Utility’s $700 million payment to the PX which decreased the restricted cash balance in 2009. (See Note 13 of the Notes to the Consolidated Financial Statements.) This increase was partially offset by a decrease in capital expenditures of $156 million as compared to 2009. Capital expenditures decreased in 2010 due to permitting delays, the postponement of purchases of materials which would otherwise have been capitalized earlier in the year, and poor weather conditions in the first half of 2010 which delayed construction activities as resources were re-directed to emergency response activities.

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Net cash used in investing decreased by $296 million in 2009 compared to 2008, primarily due to a $700 million decrease in the restricted cash balance that resulted from the Utility’s payment to the PX, partially offset by an increase of $330 million in capital expenditures. The increase in capital expenditures in 2009 compared to 2008 was due to the increase in installation of the SmartMeter™ advanced metering infrastructure, generation facility spending, replacing and expanding gas and electric distribution systems, and improving the electric transmission infrastructure. (See “Capital Expenditures” below.)

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. (See “Capital Expenditures” below for further discussion of expected spending and significant capital projects.)

Financing Activities

The Utility’s cash flows from financing activities for 2010, 2009, and 2008 were as follows:

(in millions)	2010			2009			2008
Borrowings under revolving credit facilities	$	400		$	300		$	533
Repayments under revolving credit facilities		(400	)		(300	)		(783	)
Net issuances of commercial paper, net of discount of $3 in 2010 and 2009, and $11 in 2008		267			43			6
Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2010 and 2009		249			499			—
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $23 in 2010, $25 in 2009, and $19 in 2008		1,327			1,384			2,185
Short-term debt matured		(500	)		—			—
Long-term debt matured or repurchased		(95	)		(909	)		(454	)
Energy recovery bonds matured		(386	)		(370	)		(354	)
Preferred stock dividends paid		(14	)		(14	)		(14	)
Common stock dividends paid		(716	)		(624	)		(568	)
Equity contribution		190			718			270
Other		(73	)		(5	)		(36	)
Net cash provided by financing activities	$	249		$	722		$	785

In 2010, net cash provided by financing activities decreased by $473 million compared to 2009. In 2009, net cash provided by financing activities decreased by $63 million compared to 2008. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities and the level of cash provided by or used in investing activities. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

PG&E Corporation

As of December 31, 2010, PG&E Corporation’s affiliates had entered into four tax equity agreements with two privately held companies to fund residential and commercial retail solar energy installations. Under these agreements, PG&E Corporation will provide payments of up to $300 million, and in return, receive the benefits of local rebates, federal investment tax credits or grants, and a share of these companies’ customer payments. PG&E Corporation could be required to pay up to an additional $41 million in the event that its ownership interests are liquidated when in a deficit position. (See Note 2 of the Notes to the Consolidated Financial Statements.) However, PG&E Corporation’s financial exposure for these arrangements is generally limited to its lease payments and investment contributions to these companies. As of December 31, 2010, PG&E Corporation had made total payments of $149 million under these tax equity agreements. Lease payments and investment contributions are included in cash flows from operating and investing activities, respectively, within the Consolidated Statements of Cash Flows.

In addition to the investments above, PG&E Corporation had the following material cash flows on a stand-alone basis for the years ended December 31, 2010, 2009, and 2008: dividend payments, interest payments, common stock issuance, the senior note issuance of $350 million in March 2009, net tax refunds of $189 million in 2009, and transactions between PG&E Corporation and the Utility.

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CONTRACTUAL COMMITMENTS

The following table provides information about PG&E Corporation’s and the Utility’s contractual commitments at December 31, 2010.

	Payment due by period
(in millions)	Less Than 1 Year		1–3 Years		3–5 Years		More Than 5 Years			Total
Contractual Commitments:
Utility
Long-term debt (1):
Fixed rate obligations	$	1,085	$	1,598	$	2,026	$	16,104		$	20,813
Variable rate obligations		312		635		47		307			1,301
Energy recovery bonds		435		436		—		—			871
Purchase obligations (4):
Power purchase agreements (2):
Qualifying facilities		1,086		1,720		1,617		4,392			8,815
Renewable contracts		804		2,223		3,589		40,887			47,503
Irrigation district and water agencies		80		109		47		43			279
Other power purchase agreements		694		1,512		1,189		4,227			7,622
Natural gas supply and transportation		710		464		331		1,128			2,633
Nuclear fuel		84		174		323		1,057			1,638
Pension and other benefits (3)		369		862		903		451	(6)		2,585
Capital lease obligations (4)		50		100		80		124			354
Operating leases (4)		25		41		25		73			164
Preferred dividends (5)		14		28		28		—			70
PG&E Corporation
Long-term debt (1):
Fixed rate obligations		20		40		355		—			415

⁽¹⁾ Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at December 31, 2010 and outstanding principal for each instrument with the terms ending at each instrument’s maturity. Variable rate obligations consist of bonds, due in 2016-2026, backed by letters of credit which expire in 2011 and 2012. These bonds are subject to mandatory redemption unless the letters of credit are extended or replaced or if applicable to the series, the issuer consents to the continuation of these bonds without a credit facility. Accordingly, these bonds have been classified for repayment purposes in 2011 and 2012. (See Note 4 of the Notes to the Consolidated Financial Statements.) For information on energy recovery bonds, see Note 5 of the Notes to the Consolidated Financial Statements.

⁽²⁾ This table includes power purchase agreements with plants currently under construction and assumes plants will become operational. This table does not include DWR allocated contracts because the DWR is legally and financially responsible for these contracts and payments.

⁽³⁾ PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions, sufficient to meet minimum funding requirements. (See Note 12 of the Notes to the Consolidated Financial Statements.)

⁽⁴⁾ See Note 15 of the Notes to the Consolidated Financial Statements.

⁽⁵⁾ Based on historical performance, it is assumed for purposes of the table above that dividends are payable within a fixed period of five years.

⁽⁶⁾ Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the amount reflected represents only 1 year of contributions for the Utility’s pension, pension benefit obligation plans, and long-term disability plans.

The contractual commitments table above excludes potential commitments associated with the conversion of existing overhead electric facilities to underground electric facilities. At December 31, 2010, the Utility was committed to spending approximately $236 million for these conversions. These funds are conditionally committed depending on the timing of the work, including the schedules of the respective cities, counties, and communication utilities involved. The Utility expects to spend approximately $42 million to $60 million each year in connection with these projects. Consistent with past practice, the Utility expects that these capital expenditures will be included in rate base as each individual project is completed and recoverable in rates charged to customers.

The contractual commitments table above also excludes potential payments associated with unrecognized tax benefits. Due to the uncertainty surrounding tax audits, PG&E Corporation and the Utility cannot make reliable estimates of the amount and period of future payments to major tax jurisdictions related to unrecognized tax benefits. Matters relating to tax years that remain subject to examination are discussed in Note 9 of the Notes to the Consolidated Financial Statements.

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CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies; including Chapter 11 disputed claims, claims arising from the San Bruno accident, tax matters, legal matters, and environmental matters, which are discussed in Notes 9, 13, and 15 of the Notes to the Consolidated Financial Statements.

CAPITAL EXPENDITURES

Utility

The Utility’s capital expenditures for property, plant, and equipment totaled $3.9 billion in 2010, $3.9 billion in 2009, and $3.7 billion in 2008. The Utility expects that capital expenditures will total approximately $3.7 billion in 2011. The amount of capital expenditures differs from the amount of rate base additions used for regulatory purposes primarily because capital expenditures are not added to rate base until the assets are placed in service.

The Utility makes various capital investments in its electric generation and electric and natural gas transmission and distribution infrastructure to maintain and improve system reliability, safety, and customer service; to extend the life of or replace existing infrastructure; and to add new infrastructure to meet already authorized growth. The CPUC authorizes most of the Utility’s revenue requirements to recover forecasted capital expenditures in multi-year GRCs and gas transmission and storage rate cases. The FERC authorizes revenue requirements to recover forecasted capital expenditures related to electric transmission operations in TO rate cases. (See “Regulatory Matters” below.)

In addition, from time to time, the CPUC authorizes the Utility to collect additional revenue requirements to recover capital expenditures related to specific projects. During 2010, the Utility incurred capital expenditures relating to specific CPUC-authorized projects including the continuing installation of advanced electric and gas meters using SmartMeter™ technology, electric and gas distribution reliability improvements, and the construction of the new Colusa Generation Station which commenced operations in December 2010. The CPUC also has authorized the Utility to develop renewable generation facilities using photovoltaic technology. Other projects are discussed below.

The Utility’s ability to invest in its electric and natural gas systems and develop new generation facilities is subject to many risks, including risks related to securing adequate and reasonably priced financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards. (See “Risk Factors” below.)

Proposed Oakley Generation Facility

On December 16, 2010, the CPUC voted to permit the Utility to enter into an amended purchase and sale agreement with Contra Costa Generating Station LLC for the development and construction of the 586-megawatt (“MW”) Oakley Generating Station, a natural gas-fired, combined-cycle generation facility proposed to be located in Oakley, California. Under the amended agreement, the guaranteed commercial availability date has been shifted from June 1, 2014 to June 1, 2016. Under the CPUC decision, if the Utility acquires the facility before January 1, 2016, the Utility’s associated costs cannot be recovered through rates until after January 1, 2016. Instead, the Utility’s ability to recover its costs before January 1, 2016 would depend on the amount of electric generation revenues produced by the facility. If the Utility acquires the facility after January 1, 2016, the Utility’s associated costs would be recoverable through rates. The Utility and the developer are currently negotiating an additional amendment to the purchase and sale agreement to reflect the CPUC’s decision. The Utility is uncertain whether and when the proposed amendment will be executed.

During January 2011, several parties filed applications for rehearing of the CPUC decision. PG&E Corporation and the Utility are unable to predict whether the CPUC will modify its decision based on these applications.

Proposed Manzana Wind Facility

On December 21, 2010, a proposed decision was issued in the CPUC proceeding to consider the Utility’s December 2009 application for approval of a purchase and sales agreement for the proposed 246-MW Manzana wind project and for authority to recover the estimated capital costs of $911 million in rates. On January 14, 2011, the counterparty to the agreement gave the Utility notice that it was exercising its right to terminate the agreement. On January 19, 2011, the Utility requested that the CPUC permit the Utility to withdraw the original application. It is uncertain whether or when the CPUC will grant the Utility’s request to withdraw the application.

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OFF-BALANCE SHEET ARRANGEMENTS

PG&E Corporation and the Utility do not have any other off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 2 (PG&E Corporation’s tax equity financing agreements) and Note 15 of the Notes to the Consolidated Financial Statements (the Utility’s commodity purchase agreements).

REGULATORY MATTERS

The Utility is subject to substantial regulation. Set forth below are matters pending before the CPUC, FERC, and the NRC. The resolutions of these and other proceedings may affect PG&E Corporation’s and the Utility’s results of operations or financial condition.

2011 General Rate Case Application

On October 15, 2010, the Utility, together with the CPUC’s Division of Ratepayer Advocates (“DRA”), The Utility Reform Network (“TURN”), Aglet Consumer Alliance and nearly all other intervening parties, filed a motion with the CPUC seeking approval of a settlement agreement to resolve almost all of the issues raised by the parties in the Utility’s 2011 GRC. Although the CPUC has not yet issued a final decision in the GRC proceeding, on November 19, 2010, the CPUC authorized the revenues to be approved in the CPUC’s final decision to become effective as of January 1, 2011. PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the settlement agreement.

Revenue Requirements

The settlement agreement proposes that the Utility’s total 2011 revenue requirements be increased by $395 million, including $103 million related to depreciation rate changes. In addition, the settlement agreement proposes to (1) establish a new balancing account for meter reading costs outside of the GRC that offsets $113 million requested in the GRC application and (2) remove $30 million of requested revenue requirements from the GRC for consideration in other ratemaking proceedings. Furthermore, approximately $44 million of the revenue requirement the Utility requested in the GRC application remains subject to litigation in the GRC.

The following table shows the differences, based on cost category, between the revenue requirements requested in the GRC application and the amount proposed in the settlement agreement:

(in millions)	Amounts Requested in the GRC Application			Amounts Proposed in the Settlement Agreement			Difference
Operations and maintenance	$	1,437		$	1,308		$	(129	)
Customer services		498			329			(169	)
Administrative and general		857			768			(89	)
Less: Revenue credits		(151	)		(149	)		2
Franchise fees and uncollectible customer accounts, taxes (other than income taxes), and other adjustments		188			120			(68	)
Depreciation, return, and income taxes		3,817			3,601			(216	)
Total Revenue Requirements	$	6,646		$	5,977		$	(669	)

The following paragraphs describe the revenue requirement reductions proposed in the settlement agreement compared to the amounts requested in the GRC application:

• The $129 million reduction in revenue requirements for operations and maintenance costs reflects a lower forecast of costs for, among other items, customer assistance services related to new customer connections, vegetation management, and development of utility-owned renewable generation.

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• The $169 million reduction in revenue requirements for customer services costs reflects the reduction of costs related to such items as customer retention and economic development efforts, dynamic pricing, and meter reading. While the Utility’s GRC application requested recovery of $113 million for meter reading costs in 2011, the settlement agreement proposes that these costs will instead be recovered via a new balancing account. The balancing account would track and recover incurred meter reading costs, subject to a cap of $76 million, and the Utility also would retain the cost savings attributable to decreased meter reading costs due to the installation of SmartMeter™ devices. The total of the balancing account recovery plus retained cost savings is estimated to approximate the $113 million originally requested.

• The $89 million reduction in administrative and general reflects lower funding for various PG&E Corporation and Utility corporate service functions and lower funding for employee incentive compensation. The Utility also agreed to seek recovery of $5 million of costs incurred in connection with the sale of property in another proceeding rather than the GRC.

• The $68 million reduction in revenue requirements relating to franchise fees and uncollectible customer accounts, taxes (other than income) and other adjustments, includes $44 million related to return and income taxes on the Utility’s unrecovered investment in conventional electric meters that have been replaced by SmartMeter^TM devices. The parties have agreed that this part of the Utility’s request will be litigated as part of the GRC proceeding. If the Utility is successful, the $44 million will be added back to the Utility’s 2011 electric distribution revenue requirement. The settlement agreement also would adopt a higher uncollectible revenue factor that would be used in another CPUC proceeding to determine the amount of revenue the Utility can collect to offset uncollectible customer accounts. This is expected to result in additional revenues of approximately $4 million.

• The $216 million reduction in revenue requirements for depreciation, return and income taxes consists of a $105 million decrease driven by lower depreciation rates and a $110 million decrease related to lower capital expenditures and other rate base adjustments. About $49 million of the $110 million reduction is related to the treatment of nuclear fuel and fuel oil inventory balances. Under the settlement agreement, the Utility agreed to continue recovering carrying costs on these balances at short-term interest rates (estimated to be $1 million per year based on current rates) through the energy resource recovery balancing account (“ERRA”) in accordance with the current regulatory treatment of these costs, rather than as part of the authorized GRC rate base. Another $20 million of the reduction relates to costs to implement the California Independent System Operator’s Market Redesign and Technology Update (“MRTU”). Consistent with the settlement agreement, the Utility plans to seek recovery of MRTU-related costs through the ERRA or other proceedings.

In summary, the settlement agreement proposes revenue requirements of $3.2 billion for electric distribution (as compared to $3.5 billion included in the GRC application), $1.1 billion for natural gas distribution (as compared to $1.3 billion included in the GRC application), and $1.7 billion for electric generation operations (as compared to $1.8 billion included in the GRC application).

Attrition Year Revenues

The settlement agreement proposes an attrition increase of $180 million to the authorized 2011 revenues in 2012 and an additional increase of $185 million in 2013. On a comparable basis, the Utility had requested an attrition mechanism estimated to provide increases of approximately $262 million in 2012 and approximately $334 million in 2013.

Balancing Accounts

The settlement agreement proposes to establish a new “one-way” balancing account for the Utility to recover up to approximately $20 million per year for costs associated with the Utility’s natural gas distribution integrity management program. If these costs are not spent during the GRC period, the unspent funds must be refunded to customers. However, customers would not be required to pay for costs in excess of the annual $20 million cost cap. The proposed decision also would allow the Utility to remove $113 million in forecast meter reading costs from the requested GRC revenue requirements. Instead, the Utility would record actual meter reading costs up to an annual cap of $76 million dollars in a new “one-way” meter reading balancing account. With the exception of this proposed new “one-way” balancing account and the proposed meter reading balancing account discussed above, the settlement agreement proposes to retain the existing balancing account structure without any substantial changes.

Capital Additions and Rate Base

The settlement agreement is consistent with capital expenditures for 2011 through 2013 averaging $2.2 billion to $2.3 billion per year for the portions of the Utility’s business addressed in the GRC. Proposed capital expenditures are lower than the amount included in the Utility’s GRC application, which averaged $2.7 billion per year, based on a lower forecast for new customer connections and lower capital expenditures for hydroelectric generation facilities, information technology systems, and fleet replacement. The ultimate amounts of capital expenditures will depend on a number of factors, including the level of operations and maintenance, administrative and general, and other costs.

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The settlement agreement proposes a 2011 annual average rate base of $16.6 billion for the portions of the Utility’s business reviewed in the GRC compared with the Utility’s request of $17.2 billion. The $0.6 billion difference is based on the capital expenditure reductions described above, the removal of MRTU-related capital expenditures, the continued funding of nuclear fuel and fuel oil inventory through the ERRA proceeding rather than through rate base, and the adjustment of deferred taxes to reflect the Utility’s updated estimate of the impact of 2009 bonus depreciation.

Electric Transmission Owner Rate Cases

On July 28, 2010, the Utility filed an application with the FERC requesting an annual retail transmission revenue requirement of $1.0 billion. The proposed rates represent an increase of $150 million over current authorized revenue requirements. On September 30, 2010, the FERC accepted the Utility’s filing and permitted the proposed rates to become effective on March 1, 2011, subject to refund based on a final decision to be issued by the FERC. Hearings in the case have been halted while the Utility and other parties engage in settlement negotiations. Any settlement agreement that the parties may reach will be subject to the FERC’s approval. If a settlement is not reached, the FERC will hold hearings and issue a decision after the conclusion of hearings. The Utility will begin collecting the proposed rates on March 1, 2011, and record a reserve for the amount the Utility estimates will be subject to refund.

2011 Gas Transmission and Storage Rate Case

In the Utility’s 2011 Gas Transmission and Storage rate case, the CPUC will determine the rates and terms and conditions of the Utility’s gas transmission and storage services for a four-year period beginning January 1, 2011.

Proposed Settlement Agreement

On August 20, 2010, the Utility and other parties, including TURN and the DRA, requested the CPUC to approve a proposed settlement agreement, known as the Gas Accord V Settlement Agreement (“Gas Accord V”), to set the Utility’s gas transmission and storage rates and associated revenue requirements. The CPUC’s approval of the proposed Gas Accord V is subject to the resolution of several objections raised by San Diego Gas & Electric Company and Southern California Gas Company regarding their rights and obligations under the proposed agreement. Although the CPUC has not yet issued a final decision on the Gas Accord V, on December 16, 2010, the CPUC issued a final decision that authorized the revenues to be approved in the final decision of the Gas Accord V to be effective as of January 1, 2011.

The Gas Accord V proposes a 2011 natural gas transmission and storage revenue requirement of $514 million, an increase of $52 million over the 2010 adopted revenue requirement. The proposed revenue requirement for 2012 is $541 million, $565 million for 2013, and $582 million for 2014. The Gas Accord V proposes average annual capital expenditures of $174 million and average annual depreciation costs of $112 million. The Gas Accord V provides for a 2011 operating and maintenance expense level of $105 million which would increase at an annual average rate of 2% for 2012 through 2014.

The proposed Gas Accord V maintains a majority of the terms and conditions applicable to the Utility’s natural gas transportation and storage services that had been established under previously approved settlement agreements (the first Gas Accord was approved in 1997). Under the proposed Gas Accord V, approximately 45% of the authorized revenue requirements, primarily those costs allocated to core customers, would continue to be assured of recovery through balancing account mechanisms and fixed reservation charges. The Utility’s ability to recover the remaining 55% of revenue requirements would continue to depend on throughput volumes and the extent to which non-core customers and other shippers contract for firm transmission services. To reduce the Utility’s risk of non-recovery on these remaining revenue requirements, the proposed settlement agreement includes sharing mechanisms. An under-collection or over-collection of the remaining revenue requirements associated with backbone transmission services (35% of authorized revenue requirement) would be shared equally between the Utility and customers (both core and non-core). Customers would be allocated 75% of any under-collection or over-collection of remaining revenue requirements associated with local transmission services (13% of authorized revenue requirement). Customers also would be allocated 75% of any over-collection in remaining revenue requirements associated with storage services (7% of authorized revenue requirement), but the Utility would be at risk for 100% of a net under-collection. The Gas Accord V provides for 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 that are determined in other Utility regulatory proceedings.

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Safety Phase

On October 15, 2010, the CPUC added an additional phase to the Utility’s 2011 Gas Transmission and Storage Rate Case to address the Utility’s natural gas pipeline safety, integrity, and reliability measures and the Utility’s emergency response procedures used in its natural gas transmission and storage operations. This new “safety phase” will focus on ensuring the safety and reliability of the Utility’s natural gas transmission and storage system. The CPUC will review and consider the types of protocols and procedures that the Utility should have in place or that the CPUC should immediately order to ensure the safe operation of the Utility’s gas transmission and storage operations over the next four years. The ruling notes that the new safety phase is distinct from the NTSB’s and the CPUC’s pending investigations into the cause of the San Bruno accident as well as the CPUC investigation into the Rancho Cordova accident, any proceedings that may be opened as a result of the CPUC’s investigation, and any federal or state legislation that may be adopted. The Utility expects that at the CPUC meeting to be held on February 24, 2011, the CPUC will open a new proceeding to address the safe operation of all of the natural gas pipelines in California. (See “Pending Investigations” below.)

Finally, the costs contemplated under the Gas Accord V do not include potential costs associated with the Utility’s proposed Pipeline 2020 program of initiatives, announced in October 2010, to work with regulators and industry experts to strengthen the natural gas system over the next decade. The program is expected to focus on the modernization of critical pipeline infrastructure, the use of automatic or remotely operated shut-off valves, the development of industry-leading best practices, and enhancing public safety. As part of this program, the Utility plans to create a new non-profit entity to research and develop next-generation pipeline inspection and diagnostic tools. The Utility will provide $10 million to fund this new entity at no cost to customers. The Utility is currently developing the parameters of the proposed Pipeline 2020 program and cost forecasts and anticipates filing an application with the CPUC to authorize the program in the second quarter of 2011. On December 1, 2010, the Utility requested the CPUC to permit the Utility to establish a memorandum account before the CPUC acts on the Utility’s application so the Utility can track costs incurred under the program for possible future recovery through rates. Several protests have been filed to the Utility’s request and the CPUC has not yet acted on the Utility’s request. It is possible that some of the work contemplated in the Pipeline 2020 program will be required under legislation that may be enacted in the future or by regulatory order. In that case, the Utility’s cost recovery for the mandated activities would be addressed separately by the CPUC.

PG&E Corporation and the Utility anticipate that the CPUC will issue final decisions on the Gas Accord V, the litigated issues, and safety phase during the first or second quarters of 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 through 2008 energy efficiency programs. On December 16, 2010, the CPUC awarded the Utility a final true-up payment award of $29.1 million for the 2006 through 2008 energy efficiency program cycle. Including this award, the Utility has earned incentive revenues totaling $104 million through December 31, 2010 based on the energy savings achieved through implementation of the Utility’s energy efficiency programs during the 2006 through 2008 program cycle.

With respect to the utilities’ 2009 through 2011 energy efficiency programs, the CPUC issued a decision on September 24, 2009 that changed the program cycle to cover 2010 through 2012. The CPUC authorized the Utility to collect $1.3 billion to fund its 2010 through 2012 programs, a 42% increase over the amount authorized for the 2006 through 2008 programs. The CPUC also confirmed that the risk and reward incentive mechanism would apply to the 2009 program year, subject to various modifications. The CPUC stated that applications for 2009 incentive awards are due by June 30, 2011 to enable the CPUC to issue a final decision by the end of 2011.

On November 15, 2010, a proposed decision was issued that if, adopted by the CPUC, would modify the incentive mechanism that would apply to the 2010 through 2012 program cycle. Among other changes, the proposed modification would limit the total amount of the incentive award or penalty that could be awarded to, or imposed on, all the investor-owned utilities to $189 million. If the proposed decision is adopted, the Utility’s opportunity to earn incentive revenues would be limited compared to the mechanism that was in place for the 2006-2008 program cycle.

The proposed decision notes that the CPUC may establish a new rule-making proceeding to determine what mechanism, if any, will apply to programs beginning in 2013 and later.

CPUC Resolution Regarding the Tax Relief Act

On February 7, 2011, the CPUC staff released a draft resolution that proposes to establish a memorandum account for most cost-of-service rate-regulated utilities. The memorandum account would allow the CPUC to determine whether any future rate reduction is appropriate to reflect the benefits of the Tax Relief Act not otherwise reflected in rates.

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The proposed resolution is scheduled to be considered by the CPUC on February 27, 2011. The Utility is unable to predict the outcome of this matter and whether, if the resolution is adopted, it will have a material financial impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

Deployment of SmartMeter^TM Technology

The CPUC has authorized the Utility’s program to install approximately 10 million advanced electric and gas meters throughout the Utility’s service territory by the end of 2012. 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. Advanced electric meters enable the implementation of “dynamic pricing” rates for customers that reflect the higher cost of electricity during periods of high demand. As of December 31, 2010, the Utility has installed 7.5 million meters. The CPUC has authorized the Utility to recover a maximum of $2.3 billion in estimated project costs. Costs that exceed $2.3 billion will not be recoverable through rates. As of December 31, 2010, the Utility has incurred costs of $2.0 billion. The Utility has also recorded a provision of $36 million, representing the current forecast of capital-related costs that are expected to exceed the CPUC-authorized cost cap and therefore will not be recoverable through rates. The Utility will update its forecasts as the project continues and may incur additional non-recoverable costs.

Following customer complaints that the new metering system led to overcharges, a class action lawsuit was filed against the Utility in state court, both the CPUC and a California Senate Committee began separate investigations, and several municipalities, including the City and County of San Francisco (“CCSF”), took various steps to delay or suspend the installation of the new meters. The class action lawsuit was dismissed by the court because, among other reasons, the court found that the CPUC has exclusive jurisdiction over the issues raised in the complaint. The court has permitted the plaintiff to submit an amended complaint. The California Senate Committee held hearings in April 2010 but did not take any further action before it was disbanded in early November 2010.

In June 2010, the CCSF filed a petition requesting the CPUC to temporarily suspend the installation of additional SmartMeter™ devices until the CPUC completed its investigation. On September 2, 2010, the CPUC released the report of its independent consultant’s assessment of the Utility’s installation program which found that the Utility’s SmartMeter™ devices and related billing processes perform accurately and as designed. In December 2010, the CPUC dismissed CCSF’s petition. The CPUC also dismissed a request to halt installation of the meters that had been made based on concerns about the health, environmental, and safety impacts of the radio frequency (“RF”) technology on which the Utility’s SmartMeter™ program relies. Several applications for rehearing of this decision were filed. The CPUC has not yet ruled on these applications. The CPUC also has stated that attempts by various municipalities to either suspend or prohibit the installation of SmartMeter™ devices would interfere with the CPUC’s exclusive jurisdiction over the Utility’s SmartMeter™ program. PG&E Corporation and the Utility are unable to predict the outcome of these matters.

PENDING INVESTIGATIONS

Investigations of the San Bruno Accident

Both the NTSB and the CPUC have begun investigations of the San Bruno accident but they have not yet determined the cause of the pipeline rupture. The NTSB has issued several public statements regarding the investigation and a metallurgy group report, all of which are available on the NTSB’s website. The NTSB will hold fact-finding hearings in Washington, D.C. on March 1, 2011 through March 3, 2011 and has stated that it intends to release a total of six factual reports about the San Bruno accident before the hearings begin based on the following group topics: metallurgy, operations, human performance, survival factors, fire scene, and meteorology. It is expected that these reports will be made publicly available on the NTSB’s website as each report is released.

On January 3, 2011, the NTSB issued urgent safety recommendations to the Utility to search for documentation related to its transmission pipeline system components in specified areas that have not had a maximum available operating pressure (“MAOP”) established through hydrostatic pressure testing. The NTSB also recommended that the Utility utilize traceable, verifiable and complete records to determine a valid MAOP and if the Utility is unable to do so based on appropriate records, then it should determine the MAOP by hydrostatic pressure testing. The CPUC has ordered the Utility to meet the NTSB recommendations by March 15, 2011. On February 1, 2011, the Utility submitted a status report to the CPUC describing the Utility’s extensive effort to verify pressure-testing records for over 1,800 miles of gas transmission pipelines covered by the NTSB recommendations. By the March 15, 2011 due date, the Utility expects to determine the covered pipeline segments for which it has complete, verifiable and traceable records of prior pressure tests. If the Utility is required to perform hydrostatic pressure testing on a substantial portion of its natural gas system, it could incur a material amount of costs.

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As part of the CPUC investigation, the CPUC’s staff will examine the safety of the Utility’s natural gas transmission pipelines in its service territory. The CPUC staff reviewed information about the Utility’s planned and unplanned pressurization events where the pressure has risen above the MAOP in several of the Utility’s gas transmission lines. On February 2, 2011, the CPUC ordered the Utility to reduce operating pressure twenty percent below the MAOP on certain of its gas transmission pipelines, and also ordered the Utility to reduce operating pressure on other transmission lines that meet certain criteria. The Utility has complied with the CPUC’s order and also has reported to the CPUC that the Utility has identified a number of instances where it had either exceeded MAOP by more than ten percent or had raised the pressure to maintain operational flexibility, including several instances in which the highest pressure reading exceeded MAOP by a few pounds, but not more than ten percent above MAOP.

The CPUC also has appointed an independent review panel to gather and review facts, make a technical assessment of the San Bruno accident and its root cause, and make recommendations for action by the CPUC to ensure such an accident is not repeated. The report of the independent review panel is expected in the second quarter of 2011. The recommendations arising from the CPUC’s own investigation or the investigation of the independent review panel may include changes to design, construction, operation and maintenance of natural gas facilities, management practices at the Utility in the areas of pipeline integrity and public safety, regulatory and statutory changes, and other recommendations deemed appropriate, including whether there are systemic management problems at the Utility and whether greater resources are needed to achieve fundamental infrastructure improvement.

Several parties have requested that the CPUC institute a formal public investigation of the San Bruno accident. The CPUC may consider this request at its meeting to be held on February 24, 2011. The Utility has filed a response stating that it welcomes the CPUC’s investigation. If the CPUC institutes a formal investigation, the CPUC may impose penalties on the Utility if it determines that the Utility violated any laws, rules, regulations or orders pertaining to the operations and maintenance of its natural gas system. PG&E Corporation and the Utility anticipate that the CPUC will institute one or more formal investigations regarding these matters.

In addition, the Boards of Directors of PG&E Corporation and the Utility appointed a special review committee, composed solely of independent directors, to review the Utility’s natural gas transmission and distribution operations. This review will include an assessment of current and emerging industry practices relating to gas transmission and distribution inspection, accident prevention, maintenance, capital and expense planning, engineering, and the Utility’s safety practices and culture. The committee has retained an engineering consultant to assist in this review. The review, which commenced in late 2010, is expected to be completed by the third quarter of 2011.

CPUC Investigation of the Rancho Cordova Accident

On November 19, 2010, the CPUC began a formal investigation of the Rancho Cordova accident. The explosion in a house resulted in one death, injuries to several people, and property damage. The NTSB and the CPUC’s Consumer Protection and Safety Division (“CPSD”) investigated the accident. The NTSB issued its investigative report in May 2010, and the CPSD submitted its report to the CPUC in November 2010. The NTSB determined that the probable cause of the release, ignition, and explosion of natural gas was the use of a section of unmarked and out-of-specification polyethylene pipe with inadequate wall thickness that allowed gas to leak from the mechanical coupling that had been installed on September 21, 2006. The NTSB stated that the delayed response by the Utility’s employees was a contributing factor. Based on the CPSD’s and the NTSB’s investigative findings, the CPSD requested the CPUC to open a formal investigation of the Rancho Cordova accident and recommended that the CPUC impose unspecified fines and penalties on the Utility. In its order instituting the investigation, the CPUC stated that it will determine whether the Utility violated any law, regulation, CPUC general orders or decisions, or other rules or requirements applicable to its natural gas service and facilities, and/or engaged in unreasonable and/or imprudent practices in connection with the Rancho Cordova accident. The CPUC stated that it intends to ascertain whether any management policies and practices contributed to violations of law and the Rancho Cordova accident. Finally, the CPUC noted that it may order the Utility to implement operational and policy measures designed to prevent future gas safety hazards.

The CPUC ordered the Utility to provide extensive information, from as far back as January 1, 2000, about the Utility’s practices and procedures at issue. The Utility’s report, due on February 17, 2011, agrees with the NTSB’s conclusions about the probable cause of the accident and explains what process improvements the Utility has made to prevent a similar accident in the future. The CPUC has scheduled a pre-hearing conference on March 1, 2011 to establish a schedule for the proceeding, including the date of an evidentiary hearing.

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If the CPUC determines that the Utility violated any law, regulation, CPUC general orders or decisions, or other rules or requirements applicable to the Utility’s natural gas service and facilities in connection with the San Bruno or Rancho Cordova accidents, the CPUC is authorized to impose penalties of up to $20,000 per day, per violation. The CPUC is likely to impose penalties on the Utility in connection with the Rancho Cordova accident. In addition, law enforcement authorities could begin proceedings that could result in the imposition of civil or criminal fines or penalties on the Utility. PG&E Corporation and the Utility are unable to predict the ultimate outcome of the investigations discussed above or whether additional investigations will be instituted. Further, the Utility may incur a material amount of additional expenses to comply with CPUC orders issued in connection with its investigations and such costs may not be recoverable through rates. Finally, PG&E Corporation and the Utility may suffer reputational harm which could negatively affect the value of their outstanding securities.

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. 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.

Climate Change

Although no comprehensive federal legislation to address climate change has been adopted, the California Legislature adopted the Global Warming Solutions Act of 2006 (also known as Assembly Bill 32 or “AB 32”). AB 32 requires the gradual reduction of GHG emissions in California to the 1990 levels by 2020 on a schedule beginning in 2012. The California Air Resources Board (“CARB”) is the state agency charged with setting and monitoring GHG and other emission limits. In December 2008 the CARB adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target set pursuant to AB 32. These recommendations include increasing renewable energy supplies, increasing energy efficiency goals, expanding the use of combined heat and power facilities, and developing a multi-sector cap-and-trade program. On September 23, 2010 the CARB implemented one of these recommendations by adopting regulations to require load-serving entities, including the Utility to gradually increase their deliveries of renewable energy to meet specific annual targets, culminating in a 33% target by 2020. (See discussion of these regulations below under “Renewable Energy Resources.”)

The CARB issued proposed cap-and-trade regulations for public comment in October 2010. The proposed regulations include provisions to establish state-wide caps on GHG emissions (for three 3-year compliance periods beginning January 1, 2012 and ending December 31, 2020), allocate allowances (i.e., rights to emit GHGs) among utilities and other industry participants, and permit the purchase and sale of emission allowances through a CARB-managed auction, among other provisions. After considering the comments that had been received, on December 16, 2010, the CARB directed its staff to prepare modified regulations and publish the modified regulations for one or more 15-day public comment and review periods. The modified regulations (with such further modifications as the CARB’s executive officer approves) will be submitted to the California Office of Administrative Law for final approval. If the regulations become effective, the first compliance period would begin on January 1, 2012 and apply to the electricity and industrial sectors. The second phase would begin on January 1, 2015 and would expand to include suppliers of natural gas and liquid fossil fuels.

Under the proposed cap-and-trade system, some emission allowances would be allocated to the electric sector utilities at no cost for the benefit of their customers. The investor-owned utilities are required to offer these allowances for sale in the CARB-managed auction. Auction revenues will be used to benefit the utilities’ customers. The investor-owned utilities will be required to buy allowances in the CARB auction to meet their own GHG compliance obligations. It is expected that the modified regulations will address, among other issues, the method by which allowances will be allocated to individual utilities, the method for auctioning and distributing allowances to complying entities, the enforcement mechanisms for the program, and whether the proposed allowance price containment reserve will be modified to ensure that reserve allowances are available throughout the program. It is expected that further design and implementation details will be developed over the next several months to address market manipulation concerns and other issues. In July 2011 the Executive Officer will report to the CARB on readiness to implement the cap-and-trade market and the CARB has stated it has the discretion to delay implementation if it is not prepared to proceed with the market.

Certain implementation and policy issues regarding the proposed AB 32 cap-and-trade program remain subject to resolution by the CPUC including the approved methods for utilities to procure allowances, offsets and other instruments under the program; and the rates and methods for utilities to recover compliance costs and use allowance auction revenues for the benefit of their customers. In addition, on January 21, 2011, the San Francisco County Superior Court issued a tentative decision that prohibits the CARB from implementing its cap-and-trade regulations subject to the completion of the required environmental review process.

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The ultimate financial impact of the new cap-and-trade system will depend on various factors, including the quantity of allowances that are freely allocated to utilities for customer benefit, the actual market price of emissions allowances over time, the availability of emission offsets, and the extent to which California’s cap-and-trade program is linked to other state, regional or national programs.

Renewable Energy Resources

Current California law establishes a Renewable Portfolio Standard (“RPS”) that requires California retail sellers of electricity, such as the Utility, to increase 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. Whether a retail seller who relies on flexible compliance rules has met the RPS target for a particular year may not be known until the end of the associated three-year roll-forward period. The CPUC has indicated that it currently intends to limit its discretion to levy penalties for an unexcused failure to meet an applicable RPS target to a maximum of $25 million per year per retail seller.

On January 13, 2011, the CPUC issued a decision regarding the use of tradable renewable energy credits (“RECs”) to comply with the current RPS 20% by 2010 requirements. (A tradable REC refers to a certificate of proof that one megawatt-hour (“MWh”) of renewable energy was generated. The certificate can be sold separately from the associated energy.) The CPUC’s decision, which modified an earlier decision the CPUC issued in March 2010, imposes on the three largest California investor-owned utilities, including the Utility, a temporary price cap of fifty dollars per tradable REC and a temporary quantity cap that permits the Utility to use tradable RECs for compliance with the RPS target, not to exceed 25% of their annual RPS procurement target in any year. Any tradable REC acquired in excess of this annual limit can be carried over and used for compliance in future years. The provisions imposing the price cap and the limit on the use of tradable RECs will expire on December 31, 2013. For purposes of computing the annual limit, the CPUC decision continues to classify most power-purchase contracts with out-of-state renewable generation facilities as REC-only contracts. Therefore, future deliveries of renewable energy under most of the Utility’s power-purchase contracts with out-of-state renewable generation facilities could be included in the computation of the 25% limit.

This limit, combined with the continuing challenges to the development of renewable generation resources within California, negatively affects the Utility’s ability to meet the current RPS while the limit remains in effect. Notwithstanding the CPUC’s decision, some uncertainty still exists regarding the use of tradable RECs and the ability to satisfy RPS requirements with out-of-state renewable generation because the CPUC has not yet resolved the utilities’ pending joint application for rehearing that was filed with respect to the CPUC’s original March 2010 decision.

For the year ended December 31, 2010, the Utility’s RPS-eligible renewable resource deliveries equaled 15.9% of its total retail electricity sales. The Utility intends to rely on flexible compliance rules to meet the shortfall in achieving the 2010 RPS target through deliveries of renewable energy over the next three years, the use of tradable RECs within the limit discussed above, or a combination of both. If the developers of renewable energy resources are unable to timely meet their contractual commitments to deliver RPS-eligible energy to the Utility, the Utility believes that the CPUC would consider this fact when determining whether any penalties for non-compliance should be reduced or waived.

In addition to the current RPS law, on September 23, 2010, the CARB adopted regulations that require load-serving entities, including the Utility, to gradually increase their deliveries of renewable energy to meet specific annual targets. For 2012, 2013, and 2014, the amount of electricity delivered from renewable energy resources must equal at least 20% of total energy deliveries, increasing to 24% in 2015, 2016, and 2017, 28% in 2018 and 2019, and 33% in 2020 and beyond. Under this regulation, regulated load-serving entities are allowed to use an unlimited number of tradable RECs. The CARB can impose penalties for failure to meet the targets, but it is unclear how the penalties would be calculated or whether the total penalties are subject to an annual maximum. Although the CARB did not adopt “flexible compliance rules” such as those used by the CPUC to determine compliance with current RPS requirements, the CARB directed its staff to conduct periodic public reviews to assess the effectiveness of the regulations and to recommend to the CARB any necessary modifications. The CARB also has directed its staff to modify the regulations to address concerns about the potential for excessive penalties. It is uncertain when the modified final regulations will be issued.

Finally, legislation has been introduced in the California state legislature that proposes to increase the current RPS from 20% to 33% by 2020. Under the proposed bill, Senate Bill 23, the amount of electricity delivered from renewable energy resources must

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equal at least 25% of total energy deliveries by December 31, 2016 and 33% by December 31, 2020. The proposed legislation also addresses the use of tradable RECs and contains some “flexible” compliance provisions if a utility is unable to meet the obligations. If enacted, the bill would become effective on January 1, 2012. If enacted, the new law would impose further restrictions on the utilities’ ability to satisfy RPS requirements with energy produced from out-of-state renewable generation resources. It remains unclear how this proposed legislation would affect the CARB’s regulation on renewable energy deliveries.

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 U.S. Environmental Protection Agency (“EPA”) will not issue draft revised regulations before March 2011, on May 4, 2010, the California Water Resources Control Board (“Water Board”) adopted a policy on once-through cooling. The policy, effective October 1, 2010, 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 power 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. 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

The Utility has been, and may be, required to pay for environmental remediation costs at sites where it is identified as a potentially responsible party under federal and state environmental laws. These sites include former manufactured gas plant (“MGP”) sites, current and former power plant sites, former gas gathering and gas storage sites, sites where natural gas compressor stations are located, current and former substations, service center and general construction yard sites, and sites currently and formerly used by the Utility for the storage, recycling, or disposal of hazardous substances. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site. (See Note 15 of the Notes to the Consolidated Financial Statements, for a discussion of estimated environmental remediation liabilities.)

LEGAL MATTERS

In addition to the pending investigations discussed above, various lawsuits, including two class action lawsuits, have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility related to the San Bruno accident. (See “Legal Matters” in Note 15 of the Notes to the Consolidated Financial Statements.) The Utility has filed a petition on behalf of PG&E Corporation and the Utility to coordinate these lawsuits in San Mateo County Superior Court. In its statement in support of coordination, the Utility has stated that it is prepared to enter into early mediation in an effort to resolve claims with those plaintiffs willing to do so. A hearing on the Utility’ petition is scheduled for February 24, 2011.

The Utility recorded a provision of $220 million in 2010 for estimated third-party claims related to the San Bruno accident, including personal injury and property damage claims, damage to infrastructure, and other damage claims. The Utility currently estimates that it may incur as much as $400 million for third-party claims. This estimate may change depending on the final outcome of the NTSB and CPUC investigations and the number and nature of third-party claims. As more information becomes known, including information resulting from the NTSB and CPUC investigations, management’s estimates and assumptions regarding the amount of third-party liability incurred in connection with the San Bruno accident may change. It is possible that a change in estimate could have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

In addition to these lawsuits, a purported shareholder derivative action also has been filed to seek recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims.

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PG&E Corporation also received a letter, dated October 4, 2010, on behalf of a purported shareholder demanding that the PG&E Corporation Board of Directors (1) institute an independent investigation of the San Bruno accident and related alleged safety issues; (2) seek recovery of all costs associated with such issues through legal proceedings against those determined to be responsible, including board members, officers, other employees, and third parties; and (3) adopt corporate governance initiatives and safety programs. The Board of Directors of PG&E Corporation has appointed a committee of independent directors to evaluate this demand and to make a recommendation to the Board on its responses to this demand.

PG&E Corporation and the Utility cannot predict the outcome of these matters.

PG&E Corporation and the Utility also are named as parties in a number of claims and lawsuits that have arisen in the ordinary course of business. In addition, the Utility can incur penalties for failure to comply with federal, state, or local statutes. The accrued liability for legal matters (other than third-party liability claims related to the San Bruno accident as discussed above) totaled $55 million at December 31, 2010 and $57 million at December 31, 2009 and is included in PG&E Corporation’s and the Utility’s current liabilities – other in the Consolidated Balance Sheets. See “Legal Matters” in Note 15 of the Notes to the Consolidated Financial Statements.

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” and “interest rate risk.” The Utility is also exposed to “credit risk,” the risk that counterparties fail to perform their contractual obligations.

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 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.

On July 21, 2010, President Obama signed into law new federal financial reform legislation, the Dodd-Frank Wall Street Reform and Consumer Protection Act. PG&E Corporation and the Utility are evaluating the new legislation, and will review future regulations to assess compliance requirements as well as potential impacts on the Utility’s procurement activities and risk management programs.

Price Risk

The Utility is exposed to commodity price risk as a result of its electricity and natural gas 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.

The Utility’s natural gas transportation and storage costs for non-core customers may not be fully recoverable. The Utility is subject to price and volumetric risk for the portion of intrastate natural gas transportation and storage capacity that 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 sells most of its capacity based on the volume of gas that the Utility’s customers actually ship, which exposes the Utility to 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 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 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.

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The Utility’s value-at-risk calculated under the methodology described above was approximately $11 million at December 31, 2010. The Utility’s high, low, and average values-at-risk during the 12 months ended December 31, 2010 were approximately $20 million, $10 million, and $14 million, respectively. (See Note 10 of the Notes to the 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 December 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 affect net income for the next 12 months by $6 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 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. The Utility ties many energy contracts to master commodity enabling agreements that may require security (referred to as “Credit Collateral” in the table below). Credit Collateral may be in the form of cash or letters of credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities (as deemed appropriate by the Utility). Credit Collateral or performance assurance may be required from counterparties 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 counterparties, as well as the Utility’s credit risk exposure to counterparties accounting for greater than 10% net credit exposure, as of December 31, 2010 and 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%
December 31, 2010	$	269	$	17	$	252		2	$	187
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 Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ substantially from these estimates. These policies and their key characteristics are outlined below.

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Regulatory Assets and Liabilities

The Utility’s rates are primarily set by the CPUC and the FERC and are designed to recover the cost of providing service. The Utility capitalizes and records, as a regulatory asset, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods that the costs are expected to be recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. In addition, the Utility records regulatory liabilities when the CPUC or the FERC requires a refund to be made to customers or has required that a gain or other reduction of net allowable costs be given to customers over future periods.

Determining probability requires significant judgment by management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or state court appeals. For some of the Utility’s regulatory assets, including the regulatory assets for ERBs and utility retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. The CPUC has not denied the recovery of any material costs previously recognized by the Utility as a regulatory asset during 2010, 2009, and 2008.

If the Utility determined that it is no longer probable that revenues or costs would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the revenues or costs would be charged to income in the period in which that determination was made. At December 31, 2010, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $7.6 billion and regulatory liabilities (including current balancing accounts payable) of $4.9 billion.

Loss Contingencies

PG&E Corporation and the Utility are subject to various conditions, events, and circumstances with uncertain outcomes. If it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated, PG&E Corporation and the Utility will record a loss. PG&E Corporation and the Utility evaluate the range of reasonable estimated costs and record a liability based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. These accruals, and the estimates of any additional reasonably possible losses, are reviewed quarterly and are adjusted to reflect the impacts of all information available. As discussed below, PG&E Corporation and the Utility have recorded material accruals for environmental remediation liabilities and for various legal matters.

Environmental Remediation Liabilities

The Utility is subject to loss contingencies pursuant to federal and California environmental laws and regulations that in the future may require the Utility to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party. Such contingencies may exist for the remediation of hazardous substances at various potential sites, including former MGP sites, power plant sites, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials, even if the Utility did not deposit those substances on the site.

The Utility generally commences the environmental remediation assessment process upon notification from federal or state agencies, or other parties, of a potential site requiring remedial action. (In some instances, the Utility may voluntarily initiate action to determine its remediation liability for sites that it no longer owns in cooperation with regulatory agencies. For example, the Utility has begun a voluntary program related to certain former MGP sites.) Based on such notification, the Utility completes an assessment of the potential site and evaluates whether it is probable that a remediation liability has been incurred. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can reasonably estimate the loss within a range of possible amounts. Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. Key factors evaluated in developing cost estimates include the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

When possible, the Utility estimates costs using site-specific information, but also considers historical experience for costs incurred at similar sites depending on the level of information available. Estimated costs are composed of the direct costs of the remediation effort and the costs of compensation for employees who are expected to devote a significant amount of time directly to the remediation effort. These estimated costs include remedial site investigations, remediation actions, operations and maintenance activities, post remediation monitoring, and the costs of technologies that are expected to be approved to remediate the site. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, thereby possibly affecting the cost of the remediation effort.

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At December 31, 2010 and 2009, the Utility’s accruals for undiscounted gross environmental liabilities were $612 million and $586 million, respectively. The Utility’s undiscounted future costs could increase to as much as $1.2 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements. Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized.

Legal Matters

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits, which may result in the recognition of liabilities. PG&E Corporation and the Utility record a provision for a liability when it is both probable and estimable that a liability has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated costs and record a liability based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. These accruals, and the estimates of any additional reasonably possible losses, are reviewed quarterly and are adjusted to reflect the impact of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. In assessing such contingencies, PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs. (See “Legal Matters” in Note 15 of the Notes to the Consolidated Financial Statements.)

Asset Retirement Obligations

PG&E Corporation and the Utility account for an asset retirement obligation (“ARO”) at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. A legal obligation can arise from an existing or enacted law, statute, or ordinance; a written or oral contract; or under the legal doctrine of promissory estoppel.

At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of costs as recorded in accordance with GAAP and costs recovered through the ratemaking process.

Most of PG&E Corporation’s and the Utility’s AROs relate to the Utility’s obligation to decommission its nuclear generation facilities and certain fossil-fuel generation facilities. The Utility estimates its obligation for the future decommissioning of its nuclear generation facilities and certain fossil fueled generation facilities. To estimate the liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs (which are based upon decommissioning costs studies prepared for regulatory purposes), inflation rates, and the estimated date of decommissioning. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. (See Note 2 of the Notes to the Consolidated Financial Statements.)

Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets. For example, a premature shutdown of the nuclear facilities at Diablo Canyon would increase the likelihood of an earlier start to decommissioning and cause an increase in the ARO. Additionally, if the inflation adjustment increased 25 basis points, the amount of the ARO would increase by approximately 1.37%. Similarly, an increase in the discount rate by 25 basis points would decrease the amount of the ARO by 1.02%. At December 31, 2010, the Utility’s recorded ARO for the estimated cost of retiring these assets is $1.6 billion.

Pension and Other Postretirement Plans

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees and retirees (referred to collectively as “pension benefits”), contributory postretirement medical plans for eligible employees and retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees (referred to collectively as “other postretirement benefits”). The measurement of costs and obligations to provide pension benefits and other postretirement benefits are based on a variety of factors, including the provisions of the plans, employee demographics and various actuarial calculations, assumptions, and accounting mechanisms. The assumptions are updated annually and upon any interim re-measurement of the plan obligations.

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

Changes in benefit obligations associated with these assumptions may not be recognized as costs on the statement of income. Differences between actuarial assumptions and actual plan results are deferred in accumulated other comprehensive income (loss) and are amortized into income only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market value of the related plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. As such, benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. PG&E Corporation’s and the Utility’s recorded pension expense totaled $397 million in 2010, $458 million in 2009, and $169 million in 2008. PG&E Corporation and the Utility recorded expense for other postretirement benefits of $104 million in 2010, $94 million in 2009, and $44 million in 2008.

PG&E Corporation and the Utility recognize the funded status of their respective plans on their respective Consolidated Balance Sheets with an offsetting entry to accumulated other comprehensive income (loss), resulting in no impact to their respective Consolidated Statements of Income.

Since 1993, the CPUC has authorized the Utility to recover the costs associated with its other postretirement benefits based on the annual tax-deductible contributions to the appropriate trusts. Regulatory adjustments have been recorded in the Consolidated Statements of Income and the Consolidated Balance Sheets of the Utility to reflect the difference between Utility pension expense or income for accounting purposes and Utility pension expense or income for ratemaking, which is based on a funding approach.

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

Pension and other postretirement benefit funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for pension and other postretirement benefit payments. Consistent with the trusts’ investment policies, assets are primarily invested in equity securities and fixed income securities. (See Note 12 of the Notes to the Consolidated Financial Statements.)

PG&E Corporation and the Utility review recent cost trends and projected future trends in establishing health care cost trend rates. This evaluation suggests that current rates of inflation are expected to continue in the near term. In recognition of continued high inflation in health care costs and given the design of PG&E Corporation’s plans, the assumed health care cost trend rate for 2010 is 8%, gradually decreasing to the ultimate trend rate of 5% in 2018.

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit trusts, resulting in a weighted average rate of return on plan assets. Fixed income returns were projected based on real maturity and credit spreads added to a long-term inflation rate. Equity returns were estimated based on estimates of dividend yield and real earnings growth added to a long-term rate of inflation. For the Utility’s defined benefit pension plan, the assumed return of 6.6% compares to a ten-year actual return of 6.2%.

The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 600 Aa-grade non-callable bonds at December 31, 2010. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other postretirement benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

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

(in millions)	Increase (Decrease)  in Assumption			Increase in 2010 Pension Costs		Increase in Projected Benefit Obligation at December 31, 2010
Discount rate		(0.5	)%	$	78	$	872
Rate of return on plan assets		(0.5	)%		46		—
Rate of increase in compensation		0.5	%		36		206

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

(in millions)	Increase (Decrease)  in Assumption			Increase in 2010 Other  Postretirement Benefit Costs		Increase in Accumulated Benefit Obligation at December 31, 2010
Health care cost trend rate		0.5	%	$	4	$	41
Discount rate		(0.5	)%		2		103
Rate of return on plan assets		(0.5	)%		6		—

RISK FACTORS

Risks Related to PG&E Corporation

As a holding company, PG&E Corporation depends on cash distributions and reimbursements from the Utility to meet its debt service and other financial obligations and to pay dividends on its common stock.

PG&E Corporation is a holding company with no revenue generating operations of its own. PG&E Corporation’s ability to pay interest on its outstanding debt, the principal at maturity, and to pay dividends on its common stock, as well as satisfy its other financial obligations, primarily depends on the earnings and cash flows of the Utility and the ability of the Utility to distribute cash to PG&E Corporation (in the form of dividends and share repurchases) and reimburse PG&E Corporation for the Utility’s share of applicable expenses. Before it can distribute cash to PG&E Corporation, the Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to pay preferred stock dividends, and meet its obligations to employees and creditors. If the Utility is not able to make distributions to PG&E Corporation or to reimburse PG&E Corporation, PG&E Corporation’s ability to meet its own obligations could be impaired and its ability to pay dividends could be restricted.

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

The CPUC imposed certain conditions when it approved the original formation of a holding company for the Utility, including an obligation by PG&E Corporation’s Board of Directors to give “first priority” to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. The CPUC later issued decisions adopting an expansive interpretation of PG&E Corporation’s obligations under this condition, including the requirement that PG&E Corporation “infuse the Utility with all types of capital necessary for the Utility to fulfill its obligation to serve.” The CPUC’s interpretation of PG&E Corporation’s obligation under the first priority condition could require PG&E Corporation to infuse the Utility with significant capital in the future or could prevent distributions from the Utility to PG&E Corporation, either of which could materially restrict PG&E Corporation’s ability to pay principal and interest on its outstanding debt or pay or increase its common stock dividend, meet other obligations, or execute its business strategy.

Risks Related to PG&E Corporation and the Utility

The ultimate amount of loss the Utility bears in connection with the San Bruno accident could have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition and results of operations.

PG&E Corporation and the Utility recorded a provision of $220 million in 2010 for estimated third-party claims related to the San Bruno accident, including personal injury and property damage claims, damage to infrastructure, and other damage claims. Various lawsuits have been filed by residents of San Bruno against PG&E Corporation and the Utility seeking to recover compensation for personal injury and property damage and seeking other relief. Both the NTSB and the CPUC are investigating the San Bruno accident, but the cause has not yet been determined. The CPUC has also appointed an independent review panel to gather facts, make a technical assessment of the San Bruno accident and its root cause. The Utility estimates that it may incur as much as $400 million for third-party claims depending on the final outcome of the NTSB and CPUC investigations and the number and nature of third-party claims. Management’s estimates and assumptions regarding the financial impact of the San Bruno accident may change as more information becomes known, including information resulting from the investigations by the NTSB and the CPUC.

The Utility maintains liability insurance for damages in the approximate amount of $992 million after a $10 million deductible. PG&E Corporation and the Utility currently consider it likely that most of the costs the Utility incurs for third-party claims relating to the San Bruno accident will ultimately be covered by this insurance. However, PG&E Corporation and the Utility are unable to predict the timing and amount of insurance recoveries.

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If the Utility records losses in connection with third-party claims related to the San Bruno accident that materially exceed the amount it has accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially adversely affected in the reporting periods during which additional charges are recorded depending on whether and when the Utility is able to record or collect insurance recoveries in amounts sufficient to offset such additional accruals during the same reporting periods.

In addition, the Utility currently anticipates that it will incur additional costs associated with its natural gas transmission system, including higher costs for operations, inspection, and maintenance, and costs to perform an exhaustive records search and to perform hydrostatic pressure tests. The Utility also may incur costs, beyond the amount currently anticipated, in response to NTSB or CPUC orders or requests as the investigations continue, or to comply with state or federal legislation that may be enacted that would require the Utility to make various changes to the operations and maintenance of its natural gas transmission system. If the Utility is unable to recover such costs through rates or offset the costs through operational or other cost savings, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially and adversely affected.

Finally, if the CPUC opens a formal investigation related to the San Bruno accident and/or the operations or maintenance of the Utility’s natural gas system and determines that the Utility did not comply with applicable statutes, regulations, rules, tariffs, or orders, the CPUC could order the Utility to pay penalties. In addition, law enforcement authorities could begin proceedings that could result in the imposition of civil or criminal fines or penalties on the Utility. If the Utility is required to pay civil or criminal fines or penalties, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially and adversely affected. PG&E Corporation and the Utility may suffer reputational harm which could negatively affect the value of their outstanding securities.

The Utility could incur fines or penalties in connection with the Rancho Cordova accident.

The CPUC has commenced an investigation into the Rancho Cordova accident, as discussed above. The CPUC will determine whether the Utility violated any law, regulation, CPUC general orders or decisions, or other rules or requirements applicable to its natural gas service and facilities, and/or engaged in unreasonable and/or imprudent practices in connection with the Rancho Cordova accident. The CPUC also stated that it intends to ascertain whether any management policies and practices contributed to violations of law and the Rancho Cordova accident. The CPUC may order the Utility to implement operational and policy measures designed to prevent future gas safety hazards. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially and adversely affected if the CPUC were to require the Utility to incur costs or other liabilities that are not recoverable through rates or otherwise offset by operating efficiencies or other revenues.

In addition, law enforcement authorities could begin proceedings in connection with the Rancho Cordova accident that could result in the imposition of civil or criminal fines or penalties on the Utility. If the Utility is required to pay civil or criminal fines or penalties, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially and adversely affected. PG&E Corporation and the Utility may suffer reputational harm which could negatively affect the value of their outstanding securities.

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows will be affected by the terms of future debt and equity financings.

The Utility’s ability to fund its operations, pay principal and interest on its debt, fund capital expenditures and provide collateral to support its natural gas and electricity procurement hedging contracts depends on the levels of its operating cash flow and access to the capital and credit markets. In addition, PG&E Corporation’s ability to fund its operations, make capital expenditures, and contribute equity to the Utility as needed to maintain the Utility’s CPUC-authorized equity ratio depends on the ability of the Utility to pay dividends to PG&E Corporation and PG&E Corporation’s independent access to the capital and credit markets. PG&E Corporation may also be required to access the capital markets when the Utility is successful in selling long-term debt so that it may make the equity contributions required to maintain the Utility’s applicable equity ratio.

If the Utility were unable to access the capital markets, it could be required to decrease or suspend dividends to PG&E Corporation. PG&E Corporation also would need to consider its alternatives, such as contributing capital to the Utility, to enable the Utility to fulfill its obligation to serve. If PG&E Corporation is required to contribute equity to the Utility in these circumstances, it would be required to secure these funds from the capital or credit markets.

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PG&E Corporation’s and the Utility’s ability to access the capital and credit markets and the costs and terms of available financing depend on many factors, including changes in their credit ratings, changes in the federal or state regulatory environment affecting energy companies, the overall health of the energy industry, volatility in electricity or natural gas prices, and general economic and market conditions.

Market performance or changes in other assumptions could require PG&E Corporation and the Utility to make significant unplanned contributions to its pension plan, other postretirement benefits plans, and nuclear decommissioning trusts.

PG&E Corporation and the Utility provide defined benefit pension plans and other postretirement benefits for eligible employees and retirees. The Utility also maintains three trusts for the purposes of providing funds to decommission its nuclear facilities. Up to approximately 60% of the plan assets and trust assets have generally been invested in equity securities, which are subject to market fluctuation. A decline in the market value may increase the funding requirements for these plans and trusts.

The cost of providing pension and other postretirement benefits is also affected by other factors, including the assumed rate of return on plan assets, employee demographics, discount rates used in determining future benefit obligations, rates of increase in health care costs, levels of assumed interest rates, future government regulation, and prior contributions to the plans. Similarly, funding requirements for the nuclear decommissioning trusts are affected by changes in the laws or regulations regarding nuclear decommissioning or decommissioning funding requirements, changes in assumptions as to decommissioning dates, technology and costs of labor, materials and equipment change, and assumed rate of return on plan assets. For example, changes in interest rates affect the liabilities under the plans: as interest rates decrease, the liabilities increase, potentially increasing the funding requirements.

The Utility recovers forecasted costs to fund pension and postretirement plan contributions and nuclear decommissioning through rates. If the Utility is required to make significant unplanned contributions to fund the pension and postretirement plans and nuclear decommissioning trusts and is unable to recover such contributions in rates, the contributions would negatively affect PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Other Utility obligations, such as its workers’ compensation obligations, are not separately earmarked for recovery through rates. Therefore, increases in the Utility’s workers’ compensation liabilities and other unfunded liabilities caused by a decrease in the applicable discount rate negatively impact net income.

The Utility’s ability to recover its costs may be impacted by the economy and the economy’s corresponding impact on the Utility’s customers.

The Utility is impacted by the economic cycle of the customers it serves. For example, during the last economic decline in the Utility’s service territory, customer growth slowed and customer demand decreased. Increased unemployment and a decline in the values of residential real estate resulted in an increase in unpaid customer accounts receivable. A sustained downturn or sluggishness in the economy also could reduce the Utility’s sales to industrial and commercial customers. Although the Utility generally recovers its costs through rates, regardless of sales volume, rate pressures increase when the costs are borne by a smaller sales base.

The completion of capital investment projects is subject to substantial risks, and the rate at which the Utility invests and recovers capital will directly affect net income.

The Utility’s ability to develop new generation facilities and to invest in its electric and gas systems is subject to many risks, including risks related to obtaining regulatory approval for capital investment projects, securing adequate and reasonably priced financing, obtaining and complying with the terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards. Third-party contractors on which the Utility depends to develop these projects also face many of these risks. Changes in tax laws or policies, such as those relating to production and investment tax credits for renewable energy projects, may also affect when or whether the Utility develops a potential project. The development of proposed Utility-owned renewable energy projects may also be affected by the extent to which necessary electric transmission facilities are built and evolving federal and state policies regarding the development of a “smart” electric transmission grid. In addition, reduced forecasted demand for electricity and natural gas as a result of an economic slow-down may also increase the risk that projects are deferred, abandoned, or cancelled.

If capital spending in a particular time period is greater than assumed when rates were set, earnings could be negatively affected by an increase in depreciation, taxes, and financing interest and the absence of authorized revenue requirements to recover an ROE on the amount of capital expenses that exceeds assumed amounts.

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PG&E Corporation’s and the Utility’s financial statements reflect various estimates, assumptions, and values; changes to these estimates, assumptions, and values – as well as the application of and changes in accounting rules, standards, policies, guidance, or interpretations – could materially affect PG&E Corporation’s and the Utility’s financial condition or results of operations.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of revenues, expenses, assets, and liabilities, and the disclosure of contingencies. (See the discussion under Note 1 of the Notes to the Consolidated Financial Statements and the section entitled “Critical Accounting Policies” above.) If the information on which the estimates and assumptions are based prove to be incorrect or incomplete, if future events do not occur as anticipated, or if there are changes in applicable accounting guidance, policies, or interpretation, management’s estimates and assumptions will change as appropriate. A change in management’s estimates or assumptions, or the recognition of actual losses that differ from the amount of estimated losses, could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. For example, if management can no longer assume that potentially responsible parties will pay a material share of the costs of environmental remediation or if PG&E Corporation or the Utility incurs losses in connection with environmental remediation, litigation, or other legal, administrative, or regulatory proceedings that materially exceed the provision it estimated for these liabilities, or if such amounts are not recoverable in rates, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows would be materially adversely affected.

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

The Utility’s financial condition particularly depends on its ability to recover in rates, in a timely manner, the costs of electricity and natural gas purchased for its customers, its operating expenses, and an adequate return of and on the capital invested in its utility assets, including the costs of long-term debt and equity issued to finance their acquisition. Unanticipated changes in operating expenses or capital expenditures can cause material differences between forecasted costs used to determine rates (for example, in a general rate case) and actual costs incurred, which, in turn, affect the Utility’s ability to earn its authorized rate of return. In addition, the CPUC or the FERC may not allow the Utility to recover costs that it has already incurred on the basis that such costs were not reasonably or prudently incurred or for other reasons.

The Utility has entered into a settlement agreement that, if adopted by the CPUC, will set the Utility’s revenue requirements for its basic electric and natural gas distribution operations and its electric generation operations through 2013. (See “Regulatory Matters – 2011 General Rate Case Application” above.) It is uncertain whether the settlement agreement will be approved.

The CPUC also has authorized the Utility to collect rates to recover the costs of various public policy programs that provide customer incentives and subsidies for energy efficiency programs and for the development and use of renewable and self-generation technologies. As customer rates rise to reflect these programs, subsidies, customer incentives, or shareholder incentives, the risk may increase that the CPUC or another state authority will disallow recovery of some of the Utility’s costs based on a determination that the costs were not reasonably incurred or for some other reason.

In addition, changes in laws and regulations or changes in the political and regulatory environment may have an adverse effect on the Utility’s ability to timely recover its costs and earn its authorized rate of return. During the 2000 through 2001 energy crisis that followed the implementation of California’s electric industry restructuring, the Utility could not recover in rates the high prices it had to pay for wholesale electricity, which ultimately caused the Utility to file a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In 2003, PG&E Corporation, the Utility, and the CPUC entered into a settlement agreement to resolve the Utility’s Chapter 11 proceeding, which was incorporated into the Utility’s plan of reorganization that became effective in April 2004. Even though the settlement agreement and current regulatory mechanisms contemplate that the CPUC will give the Utility the opportunity to recover its reasonable and prudent future costs of electricity and natural gas in its rates, the CPUC may not find that all of the Utility’s costs are reasonable and prudent, or the CPUC may take actions or fail to take actions that would be to the Utility’s detriment. In addition, the bankruptcy court having jurisdiction of the Chapter 11 settlement agreement or other courts may fail to implement or enforce the terms of the Chapter 11 settlement agreement and the Utility’s plan of reorganization in a manner that would produce the economic results that PG&E Corporation and the Utility intend or anticipate.

The Utility’s failure to recover any material amount of its costs through its rates in a timely manner would have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

The Utility faces uncertainties associated with the future level of bundled electric load for which it must procure electricity and secure generating capacity and, under certain circumstances, may not be able to recover all of its costs.

The Utility must procure electricity to meet customer demand, plus applicable reserve margins not satisfied from the Utility’s own generation facilities and existing electricity contracts. When customer demand exceeds the amount of electricity that can be

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economically produced from the Utility’s own generation facilities plus net energy purchase contracts (including DWR contracts allocated to the Utility’s customers), the Utility will be in a “short” position. When the Utility’s supply of electricity from its own generation resources plus net energy purchase contracts exceeds customer demand, the Utility is in a “long” position.

The amount of electricity the Utility needs to meet the demands of customers that is not satisfied from the Utility’s own generation facilities, existing purchase contracts, or DWR contracts allocated to the Utility’s customers could increase or decrease due to a variety of factors, including, without limitation a change in the number of the Utility’s customers, periodic expirations or terminations of the Utility’s existing electricity purchase contracts, termination of the DWR’s obligations to provide electricity under purchase contracts allocated to the Utility’s customers, execution of new energy and capacity purchase contracts, fluctuation in the output of hydroelectric and other renewable power facilities owned or under contract by the Utility, implementation of new energy efficiency and demand response programs, and the acquisition, retirement, or closure of generation facilities.

The amount of electricity the Utility would need to purchase would immediately increase if there were an unexpected outage at Diablo Canyon or any of its other significant generation facilities. In addition, as the electricity supplier of last resort, the amount of electricity the Utility would need to purchase also would immediately increase if a material number of customers who purchase electricity from alternate energy providers (referred to as “direct access” customers) or customers of community choice aggregators (see below) decided to return to receiving bundled services from the Utility. If the Utility’s short position unexpectedly increases, the Utility would need to purchase electricity in the wholesale market under contracts priced at the time of execution or, if made in the spot market, at the then current market price of wholesale electricity. The CPUC could disallow some or all of the costs incurred to purchase electricity under such circumstances if the CPUC determined that the Utility acted imprudently or if the CPUC found that the prices or terms of the Utility’s purchases of electricity were not reasonable. The Utility’s inability to recover its costs could have a material adverse effect on the financial condition, results of operations, or cash flows of the Utility and PG&E Corporation.

Alternatively, the Utility would be in a long position if the number of Utility customers declined because of a general economic downturn in the Utility’s service territory, or if a greater number of customers became customers of direct access providers or community choice aggregators. California law permits California cities and counties which have registered as community choice aggregators to purchase and sell electricity for their residents and businesses. The Utility would continue to provide distribution, metering, and billing services to the community choice aggregators’ customers, and would be those customers’ electricity provider of last resort. In addition, the Utility could lose customers through municipalization; the exercise of eminent domain power by municipalities to acquire and operate the Utility’s facilities which are then used to provide utility service to the municipality’s residents.

In addition, the Utility could lose customers, or experience lesser demand, because of increased customer self-generation. The risk of the loss of customers and decreased demand through self-generation is increasing as the CPUC has approved various programs to provide self-generation incentives and subsidies to customers to encourage development and use of renewable and distributed generating technologies, such as solar technology. The number of the Utility’s customers also could decline due to stricter GHG regulations or other state regulations that cause customers to leave the Utility’s service territory.

If the Utility were in a long position, the Utility would be required to sell the excess electricity purchased from third parties under electricity purchase contracts, possibly at a loss. In addition, excess electricity generated by the Utility’s own generation facilities may also have to be sold, possibly at a loss, and costs that the Utility may have incurred to develop or acquire new generation resources may become stranded.

If the CPUC fails to adjust the Utility’s rates, including non-bypassable charges, to reflect the impact of changing loads, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially adversely affected.

If the new day-ahead, hour-ahead, and real-time wholesale electricity markets that became effective in California during 2009 do not continue to function effectively, or if the Utility incurs costs to adapt to future changes to the rules governing these markets or losses in connection with congestion charges and these costs and losses are not recoverable, PG&E Corporation’s and the Utility’s results of operations, financial condition, and cash flows could be negatively impacted.

On April 1, 2009, the California Independent System Operator (“CAISO”) implemented MRTU, resulting in a new day-ahead wholesale electricity market became effective in California. Other aspects of MRTU are intended to improve electricity grid management reliability, address congestion management, increase operational efficiencies, and improve related technology infrastructure. The CAISO will be implementing additional market design features over the next several years in order to meet FERC mandates and to include features that were deferred in the initial market launch. MRTU has added significant market complexity and has required the Utility to make major changes to its systems and software interfacing with the CAISO.

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As part of MRTU, the CAISO has created congestion revenue rights (“CRRs”) to allow market participants, including load serving entities (“LSEs”), to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes both an allocation phase (in which LSEs receive CRRs at no cost based on the customer demand or “load” they serve) and an auction phase (priced at market and available to all market participants). The Utility has been allocated and has acquired via auction certain CRRs as of December 31, 2010, and anticipates acquiring additional CRRs through the allocation and auction phases. CRRs are considered derivative instruments and are recorded at fair value within the Consolidated Balance Sheets.

If the Utility incurs significant costs to implement MRTU and subsequent phases, including the costs associated with CRRs, that are not timely recovered from customers; if the new market mechanisms created by MRTU result in any price/market flaws that are not promptly and effectively corrected by the market mechanisms, the CAISO, or the FERC; if the Utility’s CRRs are not sufficient to hedge the financial risk associated with its CAISO-imposed congestion costs under MRTU; or if either the CAISO’s or the Utility’s MRTU-related systems and software do not perform as intended, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially adversely affected.

The Utility may fail to realize the benefits of its advanced metering system, the advanced metering system may fail to perform as intended, or the Utility may incur unrecoverable costs to deploy the advanced metering system and associated dynamic pricing, resulting in higher costs and/or reduced cost savings.

In 2006, the Utility began to implement the SmartMeter^TM advanced metering infrastructure project for residential and small commercial customers. This project, which is expected to be completed by the end of 2012, involves the installation of approximately 10 million advanced electricity and gas meters throughout the Utility’s service territory. There have been concerns raised about the accuracy of the meters, privacy, security, customer choice, and the safety, health and environmental aspects of the RF technology used in the system. (See “Regulatory Matters – Deployment of SmartMeter™ Technology” above.) The controversy regarding the new meters may continue, especially when the Utility implements “dynamic pricing” rates for customers as required by the CPUC. Dynamic pricing rates are designed to encourage efficient energy consumption and cost-effective demand response by more closely aligning retail rates with the wholesale electricity market.

The CPUC has authorized the Utility to recover approximately $2.3 billion in estimated project costs. Costs that exceed this amount are not recoverable. At December 31, 2010, the Utility has recorded a provision of $36 million for capital-related costs that are currently forecasted to exceed the authorized amount. If the Utility incurs additional costs that it is unable to recover through rates, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially adversely affected.

If the Utility fails to recognize the expected benefits of its advanced metering infrastructure, or if the Utility cannot integrate the new advanced metering system with its billing and other computer information systems, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially adversely affected.

If the Utility cannot timely meet the applicable resource adequacy or renewable energy requirements, the Utility may be subject to penalties. Further, the CPUC may disallow costs incurred by the Utility under power purchase agreements it enters into to meet applicable resource adequacy and renewable energy requirements if the CPUC finds that the costs are unreasonably above-market in the future.

The Utility must achieve an electricity planning reserve margin of 15% to 17% in excess of peak capacity electricity requirements. The Utility must also meet “local” resource adequacy requirements for specific regions in which locally-situated electricity capacity may be needed due to transmission constraints. The CPUC can impose a penalty if the Utility fails to acquire sufficient capacity to meet these resource adequacy requirements for a particular year. The penalty for failure to procure sufficient system resource adequacy capacity (i.e., resources that are deliverable anywhere in the CAISO-controlled electricity grid) is up to $80 per kW-year. The CPUC set the penalty for failure to meet local resource adequacy requirements at $40 per kW-year. In addition to penalties, the CAISO can require LSEs that fail to meet their resource adequacy requirements to pay the CAISO’s cost of buying electricity capacity to fulfill the LSEs’ resource adequacy target levels.

California law requires retail sellers such as the Utility to comply with the RPS by increasing their deliveries of renewable energy each year so that the amount of electricity delivered from 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 deficit to be carried forward for up to three years (i.e., to 2013), so that future deliveries of renewable power can be used to make up the deficit. The CPUC also permits the use of a limited amount of tradable RECs to meet RPS requirements. (See “Environmental Matters – Renewable Energy Resources” above.) The CPUC can impose penalties of $50 per MWh, up to $25 million per year, for an unexcused failure to comply with the current RPS requirements. The CPUC can excuse noncompliance if a retail seller is able to demonstrate good cause, such as insufficient transmission capacity or the failure of the renewable energy provider to timely develop a renewable resource.

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In addition, under its authority to implement AB 32, the CARB adopted regulations on September 23, 2010 that require virtually all load-serving entities, including the Utility, to increase their deliveries of renewable energy to meet specific annual targets. For 2012, 2013, and 2014, the amount of electricity delivered from renewable energy resources must equal at least 20% of total energy deliveries, increasing to 24% in 2015, 2016, and 2017, 28% in 2018 and 2019, and 33% in 2020 and beyond. The CARB can impose penalties for failure to meet the targets but it is unclear how the penalties would be calculated or whether the total penalties are subject to an annual maximum similar to the maximum that the CPUC adopted.

Finally, proposed legislation also has been introduced to the California Legislature that, if adopted, would increase the RPS to 33% by 2020.

Following several request for offers (“RFOs”) and bilateral negotiations, the Utility entered into various agreements to purchase renewable generation to be produced by facilities proposed to be developed by third parties. The Utility expects that it will enter into additional agreements in the future. The development of these renewable generation facilities is subject to many risks, including risks related to permitting, financing, technology, fuel supply, environmental matters, and the construction of sufficient transmission capacity. Whether the Utility can meet the renewable energy requirements depends on timely development of renewable energy facilities. Further, as the market for renewable energy develops, there is a risk that the Utility’s contractual commitments could result in procurement costs that are higher than the market price of renewable energy in the future. Although the Utility believes that it will continue to be able to recover the costs it incurs under these agreements in rates as part of the pass-through cost of electricty, there is a risk that the CPUC could disallow such costs in the future to the extent the CPUC considers the Utility’s costs to be unreasonably above market.

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

The Utility’s customers could bypass its distribution and transportation system by obtaining such services from other providers. This may result in stranded investment capital, loss of customer growth, and additional barriers to cost recovery. Forms of bypass of the Utility’s electricity distribution system include construction of duplicate distribution facilities to serve specific existing or new customers and condemnation of the Utility’s distribution facilities by local governments or municipal districts. Also, the Utility’s natural gas transportation facilities could risk being bypassed by interstate pipeline companies that construct facilities in the Utility’s markets, by customers who build pipeline connections that bypass the Utility’s natural gas transportation and distribution system, or by customers who use and transport liquefied natural gas.

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

Electricity and natural gas markets are highly volatile, and regulatory responsiveness to that volatility could be insufficient. Changing commodity prices may increase short-term cash requirements.

Commodity markets for electricity and natural gas are highly volatile and subject to substantial price fluctuations. A variety of factors that are largely outside of the Utility’s control may contribute to commodity price volatility, including:

• weather;

• residential, commercial and industrial demand;

• the availability of competitively priced alternative energy sources;

• the level of production of natural gas and natural gas supply availability, including inventory (storage);

• the availability of nuclear fuel;

• the availability of non-conventional natural gas supplies;

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• the price of fuels that are used to produce electricity, including natural gas, crude oil, coal and nuclear materials;

• the transparency, efficiency, integrity, and liquidity of regional energy markets affecting California;

• electricity transmission or natural gas transportation capacity constraints;

• federal, state, and local energy, and environmental regulation and legislation; and

• natural disasters, war, terrorism, and other catastrophic events.

The Utility’s direct exposure to natural gas price volatility will increase as the DWR electricity purchase contracts allocated to the Utility begin to expire or as the DWR contracts are terminated or assigned to the Utility. The final DWR contract is scheduled to expire in 2015. Although the Utility attempts to execute CPUC-approved hedging programs to reduce the natural gas price risk, these hedging programs may not be successful or the costs of the Utility’s hedging programs may not be fully recoverable.

Further, if wholesale electricity or natural gas prices significantly increase, public pressure, other regulatory influences, governmental influences, or other factors could constrain the CPUC from authorizing timely recovery of the Utility’s costs from customers. If the Utility cannot recover a material amount of its costs in its rates in a timely manner, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows would be materially adversely affected.

Economic downturn and the resulting drop in demand for energy commodities has reduced the prices of electricity and natural gas and required the Utility to deposit or return collateral in connection with its commodity hedging contracts. To the extent such commodity prices remain volatile, the Utility’s liquidity and financing needs may fluctuate due to the collateral requirements associated with its commodity hedging contracts. If the Utility is required to finance higher liquidity levels, the increased interest costs may negatively impact net income.

The Utility’s financial condition and results of operations could be materially adversely affected if it cannot successfully manage the risks inherent in operating the Utility’s facilities and information systems.

The Utility owns and operates extensive electricity and natural gas facilities that are interconnected to the U.S. western electricity grid and numerous interstate and continental natural gas pipelines. These interconnected systems are becoming increasingly reliant on evolving information technology systems, including the development of technologies and systems to establish a “Smart Grid” to monitor and manage the nation’s interconnected electric transmission grids. The Utility’s wide deployment of an advanced metering infrastructure throughout its service territory in California, in combination with the system changes needed to implement “dynamic pricing” for the Utility’s customers, may increase the risk of damage from a system-wide failure or from an intentional disruption of the system by third parties. The operation of the Utility’s facilities and information systems and the facilities and information systems of third parties on which it relies involves numerous risks, the realization of which can affect demand for electricity or natural gas; result in unplanned outages; reduce generating output; cause damage to the Utility’s assets or operations or those of third parties on which it relies; or subject the Utility to claims by customers or third parties for damage to property, personal injury, or the failure to maintain confidentiality of customer information. These risks include:

• operating limitations that may be imposed by environmental laws or regulations, including those relating to GHG, or other regulatory requirements;

• imposition of stricter operational performance standards by agencies with regulatory oversight of the Utility’s facilities;

• environmental accidents, including the release of hazardous or toxic substances into the air or water, urban wildfires, and other events caused by operation of the Utility’s facilities or equipment failure;

• fuel supply interruptions;

• equipment failure;

• failure or intentional disruption of the Utility’s information systems, including those relating to operations, such as the advanced metering infrastructure being deployed by the Utility, or financial information, such as customer billing;

• labor disputes, workforce shortage, and availability of qualified personnel;

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• weather, storms, earthquakes, wildland and other fires, floods or other natural disasters, war, pandemic, and other catastrophic events;

• explosions, accidents, dam failure, mechanical breakdowns, and terrorist activities; and

• other events or hazards.

The Utility’s insurance may not be sufficient or effective to provide recovery under all circumstances or against all hazards or liabilities to which the Utility is or may become subject. An uninsured loss could have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. Future insurance coverage may not be available at rates and on terms as favorable as the rates and terms of the Utility’s current insurance coverage.

The Utility may experience a labor shortage if it is unable to attract and retain qualified personnel to replace employees who retire or leave for other reasons, or the Utility’s operations may be affected by labor disruptions as a substantial number of employees are covered by collective bargaining agreements that are subject to re-negotiation as their terms expire.

The Utility’s workforce is aging and many employees will become eligible to retire within the next few years. Although the Utility has undertaken efforts to recruit and train new field service personnel, the Utility may not be successful. The Utility may be faced with a shortage of experienced and qualified personnel that could negatively impact the Utility’s operations as well as its financial condition and results of operations.

At December 31, 2010, there were 12,236 Utility employees covered by collective bargaining agreements with three unions. The terms of these agreements impact the Utility’s labor costs. While these contracts are re-negotiated, it is possible that labor disruptions could occur. In addition, it is possible that some of the remaining non-represented Utility employees will join one of these unions in the future.

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.

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. In December 2009, the EPA issued a finding that GHG emissions cause or contribute to air pollution that endangers public health and welfare. 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, there will be a need for additional generation from other sources. Under certain circumstances, 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 of the 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 significant. 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 fails 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.

The Utility’s operations are subject to extensive environmental laws, including new state cap and trade regulations, and changes in or liabilities under these laws could adversely affect its financial condition and results of operations.

The Utility’s operations are subject to extensive federal, state, and local environmental laws and permits. Complying with these environmental laws has, in the past, required significant expenditures for environmental compliance, monitoring, and pollution control equipment, as well as for related fees and permits. The Utility may incur significant expense relating to reduction of GHG, compliance with cap and trade regulations, regulation of water intake or discharge at certain facilities, and mitigation measures associated with electric and magnetic fields. Generally, the Utility has recovered the costs of complying with environmental laws and regulation in the Utility’s rates, subject to reasonableness review.

California legislation, AB 32, imposes a statewide limit on the emission of GHG that must be achieved by 2020. The CARB is developing “cap and trade” regulations that would establish state-wide annual caps on GHG emissions (from 2012 to 2020), allocate the rights to emit GHGs among utilities, and allow for the purchase and sale of emission allowances through a CARB-managed auction, among other provisions. Depending on the final form of regulations, the Utility could incur significant additional costs to

46

ensure that it complies with the new rules if they become effective as planned on January 1, 2012. In addition, the Utility expects that its cost to procure electricity from other generation providers will reflect their costs of compliance and the actual market price of emission allowances. Although these costs are expected to be passed through to customers, there can be no assurance that the CPUC will permit full recovery of these costs. These costs may change if federal or regional cap and trade programs are adopted.

In addition, the Utility already has significant liabilities (currently known, unknown, actual, and potential) related to environmental contamination at current and former Utility facilities, including natural gas compressor stations and former MGP sites, as well as at third-party-owned sites. (See “Environmental Matters” above.) The CPUC has established a special ratemaking mechanism under which the Utility is authorized to recover 90% of environmental costs associated with hazardous waste without a reasonableness review. There is no guarantee that the CPUC will not discontinue or change this ratemaking mechanism in the future. In addition, this ratemaking mechanism does not apply to remediation costs associated with the Hinkley natural gas compressor site, or to costs or losses the Utility may incur as a result of claims for property damage or personal injury.

The Utility’s environmental compliance and remediation costs could increase, and the timing of its future capital expenditures may accelerate, if standards become stricter, regulation increases, other potentially responsible parties cannot or do not contribute to cleanup costs, conditions change, or additional contamination is discovered. If the Utility must pay materially more than the amount that it currently has accrued on its Consolidated Balance Sheets to satisfy its environmental remediation obligations, and if the Utility cannot recover those or other costs of complying with environmental laws in its rates in a timely manner, or at all, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flow would be materially adversely affected.

The operation and decommissioning of the Utility’s nuclear power plants expose it to potentially significant liabilities and capital expenditures that it may not be able to recover from its insurance or other sources, adversely affecting its financial condition, results of operations, and cash flow.

Operating and decommissioning the Utility’s nuclear power plants expose it to potentially significant liabilities and capital expenditures, including not only the risk of death, injury, and property damage from a nuclear accident but matters arising from the storage, handling, and disposal of radioactive materials, including spent nuclear fuel; stringent safety and security requirements; public and political opposition to nuclear power operations; and uncertainties related to the regulatory, technological, and financial aspects of decommissioning nuclear plants when their licenses expire. The Utility maintains insurance and decommissioning trusts to reduce the Utility’s financial exposure to these risks. However, the costs or damages the Utility may incur in connection with the operation and decommissioning of nuclear power plants could exceed the amount of the Utility’s insurance coverage and other amounts set aside for these potential liabilities. In addition, as an operator of two operating nuclear reactor units, the Utility may be required under federal law to pay up to $235 million of liabilities arising out of each nuclear incident occurring not only at the Utility’s Diablo Canyon facility but at any other nuclear power plant in the United States.

The NRC has issued operating licenses for Diablo Canyon that expire in 2024 for Unit 1 and 2025 for Unit 2. In November 2009, the Utility requested that the NRC renew each of these licenses for an additional 20 years. The Utility expects the license renewal process to take many years, as the NRC conducts detailed environmental, seismic, and safety-related studies and holds public hearings. The NRC has broad authority to impose licensing and safety-related requirements that could require the Utility to incur significant capital expenditures in connection with the re-licensing process.

The NRC also has issued a license for the Utility to construct a dry cask storage facility to store spent nuclear fuel on site at Diablo Canyon. Although the dry cask storage facility is complete and the initial movement of spent fuel has occurred, an appeal of the NRC license is still pending.

If one or both units at Diablo Canyon were shut down pursuant to an NRC order; to comply with NRC licensing, safety, or security requirements; or due to other safety or operational issues, the Utility’s operating and maintenance costs would increase. Further, such events may cause the Utility to be in a short position and the Utility would need to purchase electricity from more expensive sources. In addition, the Utility’s nuclear power operations are subject to the availability of adequate nuclear fuel supplies on terms that the CPUC will find reasonable.

Furthermore, certain aspects of the Utility’s nuclear operations are subject to other federal, state, and local regulatory requirements that are overseen by other federal, state, or local agencies. For example, as discussed above under “Environmental Matters,” there is substantial uncertainty concerning the final form of federal and state regulations to implement Section 316(b) of the Clean Water Act. Depending on the nature of the final regulations that may ultimately be adopted by the EPA, the Water Board, or the California Legislature, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. If either the federal or state final regulations require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon.

47

If the CPUC prohibits the Utility from recovering a material amount of its capital expenditures, nuclear fuel costs, operating and maintenance costs, or additional procurement costs due to a determination that the costs were not reasonably or prudently incurred, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flow would be materially adversely affected.

The Utility is subject to penalties for failure to comply with federal, state, or local statutes and regulations. Changes in the political and regulatory environment could cause federal and state statutes, regulations, rules, and orders to become more stringent and difficult to comply with, and required permits, authorizations, and licenses may be more difficult to obtain, increasing the Utility’s expenses or making it more difficult for the Utility to execute its business strategy.

The Utility must comply in good faith with all applicable statutes, regulations, rules, tariffs, and orders of the CPUC, the FERC, the NRC, and other regulatory agencies relating to the aspects of its electricity and natural gas utility operations that fall within the jurisdictional authority of such agencies. These include customer billing, customer service, affiliate transactions, vegetation management, operating and maintenance practices, and safety and inspection practices. The Utility is subject to fines, penalties, and sanctions for failure to comply with applicable statutes, regulations, rules, tariffs, and orders. In particular, the CPUC may impose penalties on the Utility if the CPUC finds that the Utility violated any law, regulation, CPUC general orders or decisions, or other rules or requirements applicable to its natural gas service and facilities. The CPUC has authority to impose penalties of up to $20,000 per day, per violation. (See “Pending Investigations” above.)

Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day per violation) for failure to comply with mandatory electric reliability standards, including standards to protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches. As part of the continuing development of new and modified reliability standards, the FERC has approved changes to its Critical Infrastructure Protection reliability standards (effective April 1, 2010) that will establish a compliance schedule for assets that a utility has identified as “critical cyber assets.” As these and other standards and rules evolve, and as the wholesale electricity markets become more complex, the Utility’s risk of noncompliance may increase.

In addition, there is risk that these statutes, regulations, rules, tariffs, and orders may become more stringent and difficult to comply with in the future, or that their interpretation and application may change over time and that the Utility will be determined to have not complied with such new interpretations. If this occurs, the Utility could be exposed to increased costs to comply with the more stringent requirements or new interpretations and to potential liability for customer refunds, penalties, or other amounts. If it is determined that the Utility did not comply with applicable statutes, regulations, rules, tariffs, or orders, and the Utility is ordered to pay a material amount in customer refunds, penalties, or other amounts, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flow would be materially adversely affected.

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

If the Utility cannot obtain, renew, or comply with necessary governmental permits, authorizations, or licenses, or if the Utility cannot recover any increased costs of complying with additional license requirements or any other associated costs in its rates in a timely manner, PG&E Corporation’s and the Utility’s financial condition and results of operations could be materially adversely affected.

48

PG&E Corporation

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

	Year ended December 31,
	2010			2009			2008
Operating Revenues
Electric	$	10,645		$	10,257		$	10,738
Natural gas		3,196			3,142			3,890
Total operating revenues		13,841			13,399			14,628
Operating Expenses
Cost of electricity		3,898			3,711			4,425
Cost of natural gas		1,291			1,291			2,090
Operating and maintenance		4,439			4,346			4,201
Depreciation, amortization, and decommissioning		1,905			1,752			1,651
Total operating expenses		11,533			11,100			12,367
Operating Income		2,308			2,299			2,261
Interest income		9			33			94
Interest expense		(684	)		(705	)		(728	)
Other income (expense), net		27			67			(4	)
Income Before Income Taxes		1,660			1,694			1,623
Income tax provision		547			460			425
Income From Continuing Operations		1,113			1,234			1,198
Discontinued Operations
NEGT income tax benefit		—			—			154
Net Income		1,113			1,234		$	1,352
Preferred stock dividend requirement of subsidiary		14			14			14
Income Available for Common Shareholders	$	1,099		$	1,220		$	1,338
Weighted Average Common Shares Outstanding, Basic		382			368			357
Weighted Average Common Shares Outstanding, Diluted		392			386			358
Earnings Per Common Share from Continuing Operations, Basic	$	2.86		$	3.25		$	3.23
Net Earnings Per Common Share, Basic	$	2.86		$	3.25		$	3.64
Earnings Per Common Share from Continuing Operations, Diluted	$	2.82		$	3.20		$	3.22
Net Earnings Per Common Share, Diluted	$	2.82		$	3.20		$	3.63
Dividends Declared Per Common Share	$	1.82		$	1.68		$	1.56

See accompanying Notes to the Consolidated Financial Statements.

49

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2010			2009
ASSETS
Current Assets
Cash and cash equivalents	$	291		$	527
Restricted cash ($38 and $39 related to energy recovery bonds at December 31, 2010 and 2009, respectively)		563			633
Accounts receivable
Customers (net of allowance for doubtful accounts of $81 and $68 at December 31, 2010 and 2009, respectively)		944			859
Accrued unbilled revenue		649			671
Regulatory balancing accounts		1,105			1,109
Other		794			750
Regulatory assets		599			427
Inventories
Gas stored underground and fuel oil		152			114
Materials and supplies		205			200
Income taxes receivable		47			127
Other		193			240
Total current assets		5,542			5,657
Property, Plant, and Equipment
Electric		33,508			30,481
Gas		11,382			10,697
Construction work in progress		1,384			1,888
Other		15			14
Total property, plant, and equipment		46,289			43,080
Accumulated depreciation		(14,840	)		(14,188	)
Net property, plant, and equipment		31,449			28,892
Other Noncurrent Assets
Regulatory assets ($735 and $1,124 related to energy recovery bonds at December 31, 2010 and 2009, respectively)		5,846			5,522
Nuclear decommissioning trusts		2,009			1,899
Income taxes receivable		565			596
Other		614			379
Total other noncurrent assets		9,034			8,396
TOTAL ASSETS	$	46,025		$	42,945

See accompanying Notes to the Consolidated Financial Statements.

50

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2010			2009
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	853		$	833
Long-term debt, classified as current		809			342
Energy recovery bonds, classified as current		404			386
Accounts payable
Trade creditors		1,129			984
Disputed claims and customer refunds		745			773
Regulatory balancing accounts		256			281
Other		379			349
Interest payable		862			818
Income taxes payable		77			214
Deferred income taxes		113			332
Other		1,558			1,501
Total current liabilities		7,185			6,813
Noncurrent Liabilities
Long-term debt		10,906			10,381
Energy recovery bonds		423			827
Regulatory liabilities		4,525			4,125
Pension and other postretirement benefits		2,234			1,773
Asset retirement obligations		1,586			1,593
Deferred income taxes		5,547			4,732
Other		2,085			2,116
Total noncurrent liabilities		27,306			25,547
Commitments and Contingencies (Note 15)
Equity
Shareholders’ Equity
Preferred stock		—			—
Common stock, no par value, authorized 800,000,000 shares, 395,227,205 shares outstanding at December 31, 2010 and 371,272,457 shares outstanding at December 31, 2009		6,878			6,280
Reinvested earnings		4,606			4,213
Accumulated other comprehensive loss		(202	)		(160	)
Total shareholders’ equity		11,282			10,333
Noncontrolling Interest – Preferred Stock of Subsidiary		252			252
Total equity		11,534			10,585
TOTAL LIABILITIES AND EQUITY	$	46,025		$	42,945

See accompanying Notes to the Consolidated Financial Statements.

51

PG&E Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2010			2009			2008
Cash Flows from Operating Activities
Net income	$	1,113		$	1,234		$	1,352
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		2,151			1,947			1,863
Allowance for equity funds used during construction		(110	)		(94	)		(70	)
Deferred income taxes and tax credits, net		756			809			590
Other		47			(26	)		(6	)
Effect of changes in operating assets and liabilities:
Accounts receivable		(44	)		156			(87	)
Inventories		(43	)		109			(59	)
Accounts payable		48			(40	)		(140	)
Disputed claims and customer refunds		—			(700	)		—
Income taxes receivable/payable		(78	)		171			(59	)
Other current assets		(9	)		122			(185	)
Other current liabilities		120			172			90
Regulatory assets, liabilities, and balancing accounts, net		(394	)		(516	)		(374	)
Other changes in noncurrent assets and liabilities		(351	)		(305	)		(152	)
Net cash provided by operating activities		3,206			3,039			2,763
Cash Flows from Investing Activities
Capital expenditures		(3,802	)		(3,958	)		(3,628	)
Decrease in restricted cash		66			666			36
Proceeds from sales and maturities of nuclear decommissioning trust investments		1,405			1,351			1,635
Purchases of nuclear decommissioning trust investments		(1,456	)		(1,414	)		(1,684	)
Other		(70	)		19			(11	)
Net cash used in investing activities		(3,857	)		(3,336	)		(3,652	)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities		490			300			533
Repayments under revolving credit facilities		(490	)		(300	)		(783	)
Net issuances of commercial paper, net of discount of $3 in 2010 and 2009, and $11 in 2008		267			43			6
Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2010 and 2009		249			499			—
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $23 in 2010, $29 in 2009, and $19 in 2008		1,327			1,730			2,185
Short-term debt matured		(500	)		—			—
Long-term debt matured or repurchased		(95	)		(909	)		(454	)
Energy recovery bonds matured		(386	)		(370	)		(354	)
Common stock issued		303			219			225
Common stock dividends paid		(662	)		(590	)		(546	)
Other		(88	)		(17	)		(49	)
Net cash provided by financing activities		415			605			763
Net change in cash and cash equivalents		(236	)		308			(126	)
Cash and cash equivalents at January 1		527			219			345
Cash and cash equivalents at December 31	$	291		$	527		$	219
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(627	)	$	(612	)	$	(523	)
Income taxes, net		(135	)		359			112
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	183		$	157		$	143
Capital expenditures financed through accounts payable		364			273			348
Noncash common stock issuances		265			50			22

See accompanying Notes to the Consolidated Financial Statements.

52

PG&E Corporation

CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)

	Common Stock Shares			Common Stock Amount			Common Stock Held by Subsidiary			Reinvested Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity			Noncontrolling Interest – Preferred Stock of Subsidiary		Total Equity			Comprehensive Income
Balance at December 31, 2007		379,646,276		$	6,110		$	(718	)	$	3,151		$	10		$	8,553		$	252	$	8,805
Income available for common shareholders		—			—			—			1,338			—			1,338			—		1,338		$	1,338
Employee benefit plan adjustment (net of income tax benefit of $156)		—			—			—			—			(231	)		(231	)		—		(231	)		(231	)
Comprehensive income																								$	1,107
Common stock issued, net		7,365,909			247			—			—			—			247			—		247
Common stock cancelled		(24,665,500	)		(403	)		718			(315	)		—			—			—		—
Stock-based compensation amortization		—			24			—			—			—			24			—		24
Common stock dividends declared and paid		—			—			—			(417	)		—			(417	)		—		(417	)
Common stock dividends declared but not yet paid		—			—			—			(143	)		—			(143	)		—		(143	)
Tax benefit from employee stock plans		—			6			—			—			—			6			—		6
Balance at December 31, 2008		362,346,685			5,984			—			3,614			(221	)		9,377			252		9,629
Income available for common shareholders		—			—			—			1,220			—			1,220			—		1,220		$	1,220
Employee benefit plan adjustment (net of income tax expense of $8 )		—			—			—			—			61			61			—		61			61
Comprehensive income																								$	1,281
Common stock issued, net		8,925,772			269			—			—			—			269			—		269
Stock-based compensation amortization		—			20			—			—			—			20			—		20
Common stock dividends declared and paid		—			—			—			(464	)		—			(464	)		—		(464	)
Common stock dividends declared but not yet paid		—			—			—			(157	)		—			(157	)		—		(157	)
Tax benefit from employee stock plans		—			7			—			—			—			7			—		7
Balance at December 31, 2009		371,272,457			6,280			—			4,213			(160	)		10,333			252		10,585
Net income		—			—			—			1,113			—			1,113			—		1,113		$	1,113
Employee benefit plan adjustment (net of income tax benefit of $25)		—			—			—			—			(42	)		(42	)		—		(42	)		(42	)
Comprehensive income																								$	1,071
Common stock issued, net		23,954,748			568			—			—			—			568			—		568
Stock-based compensation amortization		—			34			—			—			—			34			—		34
Common stock dividends declared		—			—			—			(706	)		—			(706	)		—		(706	)
Tax expense from employee stock plans		—			(4	)		—			—			—			(4	)		—		(4	)
Preferred stock dividend requirement of subsidiary		—			—			—			(14	)		—			(14	)		—		(14	)
Balance at December 31, 2010		395,227,205		$	6,878		$	—		$	4,606		$	(202	)	$	11,282		$	252	$	11,534

See accompanying Notes to the Consolidated Financial Statements.

53

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

	Year ended December 31,
	2010			2009			2008
Operating Revenues
Electric	$	10,644		$	10,257		$	10,738
Natural gas		3,196			3,142			3,890
Total operating revenues		13,840			13,399			14,628
Operating Expenses
Cost of electricity		3,898			3,711			4,425
Cost of natural gas		1,291			1,291			2,090
Operating and maintenance		4,432			4,343			4,197
Depreciation, amortization, and decommissioning		1,905			1,752			1,650
Total operating expenses		11,526			11,097			12,362
Operating Income		2,314			2,302			2,266
Interest income		9			33			91
Interest expense		(650	)		(662	)		(698	)
Other income, net		22			59			28
Income Before Income Taxes		1,695			1,732			1,687
Income tax provision		574			482			488
Net Income		1,121			1,250			1,199
Preferred stock dividend requirement		14			14			14
Income Available for Common Stock	$	1,107		$	1,236		$	1,185

See accompanying Notes to the Consolidated Financial Statements.

54

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2010			2009
ASSETS
Current Assets
Cash and cash equivalents	$	51		$	334
Restricted cash ($38 and $39 related to energy recovery bonds at December 31, 2010 and 2009, respectively)		563			633
Accounts receivable
Customers (net of allowance for doubtful accounts of $81 at and $68 at December 31, 2010 and 2009, respectively)		944			859
Accrued unbilled revenue		649			671
Regulatory balancing accounts		1,105			1,109
Other		856			751
Regulatory assets		599			427
Inventories
Gas stored underground and fuel oil		152			114
Materials and supplies		205			200
Income taxes receivable		48			138
Other		190			235
Total current assets		5,362			5,471
Property, Plant, and Equipment
Electric		33,508			30,481
Gas		11,382			10,697
Construction work in progress		1,384			1,888
Total property, plant, and equipment		46,274			43,066
Accumulated depreciation		(14,826	)		(14,175	)
Net property, plant, and equipment		31,448			28,891
Other Noncurrent Assets
Regulatory assets ($735 and $1,124 related to energy recovery bonds at December 31, 2010 and 2009, respectively)		5,846			5,522
Nuclear decommissioning trusts		2,009			1,899
Income taxes receivable		614			610
Other		400			316
Total other noncurrent assets		8,869			8,347
TOTAL ASSETS	$	45,679		$	42,709

See accompanying Notes to the Consolidated Financial Statements.

55

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2010			2009
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	853		$	833
Long-term debt, classified as current		809			95
Energy recovery bonds, classified as current		404			386
Accounts payable
Trade creditors		1,129			984
Disputed claims and customer refunds		745			773
Regulatory balancing accounts		256			281
Other		390			363
Interest payable		857			813
Income taxes payable		116			223
Deferred income taxes		118			334
Other		1,349			1,307
Total current liabilities		7,026			6,392
Noncurrent Liabilities
Long-term debt		10,557			10,033
Energy recovery bonds		423			827
Regulatory liabilities		4,525			4,125
Pension and other postretirement benefits		2,174			1,717
Asset retirement obligations		1,586			1,593
Deferred income taxes		5,659			4,764
Other		2,008			2,073
Total noncurrent liabilities		26,932			25,132
Commitments and Contingencies (Note 15)
Shareholders’ Equity
Preferred stock		258			258
Common stock, $5 par value, authorized 800,000,000 shares, 264,374,809 shares outstanding at December 31, 2010 and 2009		1,322			1,322
Additional paid-in capital		3,241			3,055
Reinvested earnings		7,095			6,704
Accumulated other comprehensive loss		(195	)		(154	)
Total shareholders’ equity		11,721			11,185
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	45,679		$	42,709

See accompanying Notes to the Consolidated Financial Statements.

56

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2010			2009			2008
Cash Flows from Operating Activities
Net income	$	1,121		$	1,250		$	1,199
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		2,116			1,927			1,838
Allowance for equity funds used during construction		(110	)		(94	)		(70	)
Deferred income taxes and tax credits, net		762			787			593
Other		46			(27	)		(6	)
Effect of changes in operating assets and liabilities:
Accounts receivable		(105	)		157			(83	)
Inventories		(43	)		109			(59	)
Accounts payable		109			(33	)		(137	)
Disputed claims and customer refunds		—			(700	)		—
Income taxes receivable/payable		(58	)		21			43
Other current assets		(7	)		122			(187	)
Other current liabilities		130			183			60
Regulatory assets, liabilities, and balancing accounts, net		(394	)		(516	)		(374	)
Other changes in noncurrent assets and liabilities		(331	)		(282	)		(51	)
Net cash provided by operating activities		3,236			2,904			2,766
Cash Flows from Investing Activities
Capital expenditures		(3,802	)		(3,958	)		(3,628	)
Decrease in restricted cash		66			666			36
Proceeds from sales and maturities of nuclear decommissioning trust investments		1,405			1,351			1,635
Purchases of nuclear decommissioning trust investments		(1,456	)		(1,414	)		(1,684	)
Other		19			11			1
Net cash used in investing activities		(3,768	)		(3,344	)		(3,640	)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities		400			300			533
Repayments under revolving credit facilities		(400	)		(300	)		(783	)
Net issuances of commercial paper, net of discount of $3 in 2010 and 2009, and $11 in 2008		267			43			6
Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2010 and 2009		249			499			—
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $23 in 2010, $25 in 2009, and $19 in 2008		1,327			1,384			2,185
Short-term debt matured		(500	)		—			—
Long-term debt matured or repurchased		(95	)		(909	)		(454	)
Energy recovery bonds matured		(386	)		(370	)		(354	)
Preferred stock dividends paid		(14	)		(14	)		(14	)
Common stock dividends paid		(716	)		(624	)		(568	)
Equity contribution		190			718			270
Other		(73	)		(5	)		(36	)
Net cash provided by financing activities		249			722			785
Net change in cash and cash equivalents		(283	)		282			(89	)
Cash and cash equivalents at January 1		334			52			141
Cash and cash equivalents at December 31	$	51		$	334		$	52
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(595	)	$	(578	)	$	(496	)
Income taxes, net		(171	)		170			95
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	364		$	273		$	348

See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in millions)

	Preferred Stock		Common Stock			Additional Paid-in Capital			Common Stock Held by Subsidiary			Reinvested Earnings			Accumulated Other Comprehensive Income (Loss)			Total Share- holders’ Equity			Comprehensive Income
Balance at December 31, 2007	$	258	$	1,415		$	2,220		$	(475	)	$	5,694		$	13		$	9,125
Net income		—		—			—			—			1,199			—			1,199		$	1,199
Employee benefit plan adjustment (net of income tax expense of $159)		—		—			—			—			—			(229	)		(229	)		(229	)
Comprehensive income																					$	970
Equity contribution		—		4			266			—			—			—			270
Tax benefit from employee stock plans		—		—			4			—			—			—			4
Common stock dividend		—		—			—			—			(568	)		—			(568	)
Common stock cancelled		—		(97	)		(159	)		475			(219	)		—			—
Preferred stock dividend		—		—			—			—			(14	)		—			(14	)
Balance at December 31, 2008		258		1,322			2,331			—			6,092			(216	)		9,787
Net income		—		—			—			—			1,250			—			1,250		$	1,250
Employee benefit plan adjustment (net of income tax expense of $10)		—		—			—			—			—			62			62			62
Comprehensive income																					$	1,312
Equity contribution		—		—			718			—			—			—			718
Tax benefit from employee stock plans		—		—			6			—			—			—			6
Common stock dividend		—		—			—			—			(624	)		—			(624	)
Preferred stock dividend		—		—			—			—			(14	)		—			(14	)
Balance at December 31, 2009		258		1,322			3,055			—			6,704			(154	)		11,185
Net income		—		—			—			—			1,121			—			1,121		$	1,121
Employee benefit plan adjustment (net of income tax benefit of $25)		—		—			—			—			—			(41	)		(41	)		(41	)
Comprehensive income																					$	1,080
Equity contribution		—		—			190			—			—			—			190
Tax expense from employee stock plans		—		—			(4	)		—			—			—			(4	)
Common stock dividend		—		—			—			—			(716	)		—			(716	)
Preferred stock dividend		—		—			—			—			(14	)		—			(14	)
Balance at December 31, 2010	$	258	$	1,322		$	3,241		$	—		$	7,095		$	(195	)	$	11,721

See accompanying Notes to the Consolidated Financial Statements.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is regulated 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 is a combined annual report of PG&E Corporation and the Utility. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated from the Consolidated Financial Statements.

The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the Securities and Exchange Commission (“SEC”). 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 relate to the Utility’s regulatory assets and liabilities, environmental remediation liabilities, asset retirement obligations (“ARO”), and pension plan and other postretirement plan obligations. In addition, management has made significant estimates and assumptions for accruals related to the rupture of a natural gas transmission pipeline owned and operated by the Utility in the City of San Bruno, California on September 9, 2010, as well as accruals for various legal matters. (See Note 15 below.) Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. Actual results could differ materially from those estimates.

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at cost, which approximates fair value. PG&E Corporation and the Utility invest their cash primarily in money market funds.

Restricted Cash

Restricted cash consists primarily of the Utility’s cash held in escrow pending the resolution of the remaining disputed claims made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”). (See Note 13 below.) Restricted cash also includes the Utility’s deposits of cash and cash equivalents made under certain third-party agreements.

Allowance for Doubtful Accounts Receivable

PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record accounts receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.

Inventories

Inventories are carried at weighted average cost and are valued at the lower of weighted-average cost or market. Inventories include materials, supplies, and natural gas stored underground. Materials and supplies are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when consumed or installed. Natural gas stored underground represents purchases that are injected into inventory and then expensed at average cost when withdrawn and distributed to customers or used in electric generation.

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Property, Plant, and Equipment

Property, plant, and equipment are reported at their original cost. These original costs include labor and materials, construction overhead, and allowance for funds used during construction (“AFUDC”).

The Utility’s balances at December 31, 2010 are as follows:

(in millions)	Gross Plant as of December 31, 2010		Accumulated Depreciation as  of December 31, 2010			Net Plant as of December 31, 2010
Electricity generating facilities (1)	$	6,012	$	(1,404	)	$	4,608
Electricity distribution facilities		20,991		(7,161	)		13,830
Electricity transmission		6,505		(1,829	)		4,676
Natural gas distribution facilities		7,443		(2,819	)		4,624
Natural gas transportation and storage		3,939		(1,613	)		2,326
Construction work in progress		1,384		—			1,384
Total	$	46,274	$	(14,826	)	$	31,448

⁽¹⁾ Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 15 below.)

The Utility’s balances at December 31, 2009 are as follows:

(in millions)	Gross Plant as of December 31, 2009		Accumulated Depreciation as  of December 31, 2009			Net Plant as of December 31, 2009
Electricity generating facilities (1)	$	4,777	$	(1,279	)	$	3,498
Electricity distribution facilities		19,924		(6,924	)		13,000
Electricity transmission		5,780		(1,751	)		4,029
Natural gas distribution facilities		7,069		(2,667	)		4,402
Natural gas transportation and storage		3,628		(1,554	)		2,074
Construction work in progress		1,888		—			1,888
Total	$	43,066	$	(14,175	)	$	28,891

⁽¹⁾ Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 15 below.)

AFUDC

AFUDC is a method used to compensate the Utility for the estimated cost of debt (interest) and equity funds used to finance regulated plant additions and is capitalized as part of the cost of construction projects. AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service. The portion of AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC of $110 million and $50 million during 2010, $95 million and $44 million during 2009, $70 million and $44 million during 2008, related to equity and debt, respectively.

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Depreciation

The Utility depreciates property, plant, and equipment on a straight-line basis over the estimated useful lives. The composite, or group, method of depreciation is used, in which a single depreciation rate is applied to the gross investment in a particular class of property. The Utility’s composite depreciation rate was 3.38% in 2010, 3.43% in 2009, and 3.38% in 2008.

	Estimated Useful Lives
Electricity generating facilities		4 to 37 years
Electricity distribution facilities		16 to 58 years
Electricity transmission		40 to 70 years
Natural gas distribution facilities		24 to 52 years
Natural gas transportation and storage		25 to 48 years

The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged to accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.

Capitalized Software Costs

PG&E Corporation and the Utility capitalize costs incurred during the application development stage of internal use software projects to property, plant, and equipment. PG&E Corporation and the Utility amortize capitalized software costs ratably over the expected lives of the software, ranging from 3 to 15 years and commencing upon operational use. Capitalized software costs totaled $580 million at December 31, 2010 and $562 million at December 31, 2009, net of accumulated amortization of $386 million at December 31, 2010 and $315 million at December 31, 2009. Amortization expense for capitalized software was $94 million in 2010, $37 million in 2009, and $73 million in 2008. Amortization expense is estimated to be approximately $120 million annually for 2011 through 2015.

Regulation and Regulated Operations

As a regulated entity, the Utility’s rates are designed to recover the costs of providing service. The Utility capitalizes and records, as a regulatory asset, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods that the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. In addition, amounts that are probable of being credited or refunded to customers in the future are recorded as regulatory liabilities.

The Utility uses regulatory balancing accounts to accumulate differences between actual billed and unbilled revenues and the Utility’s authorized revenue requirements for the period. The Utility also uses regulatory balancing accounts to accumulate differences between incurred costs and actual billed and unbilled revenues, as well as differences between incurred costs and authorized revenue meant to recover those costs. Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being refunded to customers are recorded as regulatory balancing account liabilities. For further discussion please see “Revenue Recognition” below.

To the extent that portions of the Utility’s operations cease to be subject to cost-of-service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.

Intangible Assets

Intangible assets primarily consist of hydroelectric facility licenses with lives ranging from 19 to 40 years. The gross carrying amount of the hydroelectric facility licenses and other agreements was $112 million at December 31, 2010 and $110 million at December 31, 2009. The accumulated amortization was $44 million at December 31, 2010 and $40 million at December 31, 2009.

The Utility’s amortization expense related to intangible assets was $4 million in 2010, 2009, and 2008. The estimated annual amortization expense for 2011 through 2015 based on the December 31, 2010 intangible assets balance is $3 million. Intangible assets are recorded to other noncurrent assets – other in the Consolidated Balance Sheets.

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Asset Retirement Obligations

PG&E Corporation and the Utility record an ARO at fair value in the period in which the obligation is incurred if the fair value can be reasonably estimated. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value, and the capitalized cost is depreciated over the useful life of the long-lived asset. PG&E Corporation and the Utility also record a liability if a legal obligation to perform an asset retirement exists and can be reasonably estimated, but performance is conditional upon a future event. The Utility recognizes regulatory assets or liabilities as a result of timing differences between the recognition of costs and the costs recovered through the ratemaking process.

The Utility has an ARO for its nuclear generation and certain fossil fueled generation facilities. The Utility has also identified AROs related to asbestos contamination in buildings, potential site restoration at certain hydroelectric facilities, fuel storage tanks, and contractual obligations to restore leased property to pre-lease condition. Additionally, the Utility has recorded AROs related to gas distribution, gas transmission, electric distribution, and electric transmission system assets.

Detailed studies of the cost to decommission the Utility’s nuclear power plants are conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceedings (“NDCTP”) conducted by the CPUC. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’s nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. Estimated cash flows were revised as a result of the studies completed in the first quarter of 2009.

For GAAP purposes, the Utility adjusts its nuclear decommissioning obligation to reflect changes in the estimate of decommissioning its nuclear power facilities and records this as an adjustment to ARO on its Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was $1.2 billion at December 31, 2010 and $1.4 billion at December 31, 2009. For regulatory purposes, the estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was approximately $2.3 billion at December 31, 2010 and 2009 (or approximately $4.4 billion and $4.6 billion in future dollars, respectively). These estimates are based on the 2009 decommissioning cost studies, prepared in accordance with CPUC requirements.

Differences between amounts collected in rates for decommissioning the Utility’s nuclear power facilities and the decommissioning obligation recorded in accordance with GAAP are reflected as a regulatory liability. (See Note 3 below.)

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		(129	)
Accretion		98
Liabilities settled		(60	)
ARO liability at December 31, 2009		1,593
Revision in estimated cash flows		(23	)
Accretion		93
Liabilities settled		(77	)
ARO liability at December 31, 2010	$	1,586

The Utility has identified additional ARO for which a reasonable estimate of fair value could not be made. The Utility has not recognized a liability related to these additional obligations, which include obligations to restore land to its pre-use condition under the terms of certain land rights agreements, removal and proper disposal of lead-based paint contained in some Utility facilities, removal of certain communications equipment from leased property, and retirement activities associated with substation and certain hydroelectric facilities. The Utility was not able to reasonably estimate the ARO associated with these assets because the settlement date of the obligation was indeterminate and information sufficient to reasonably estimate the settlement date or range of settlement dates does not exist. Land rights, communications equipment leases, and substation facilities will be maintained for the foreseeable future, and therefore, the Utility cannot reasonably estimate the settlement date or range of settlement dates for the obligations associated with these assets. The Utility does not have information available that specifies which facilities contain lead-based paint and, therefore, cannot reasonably estimate the settlement date(s) associated with the obligation. The Utility will maintain and continue to operate its hydroelectric facilities until the operation of a facility becomes uneconomical. The operation of the majority of the Utility’s hydroelectric facilities is currently, and for the foreseeable future, economically beneficial. Therefore, the settlement date cannot be determined at this time.

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Impairment of Long-Lived Assets

PG&E Corporation and the Utility evaluate the carrying amounts of long-lived assets for impairment, based on projections of undiscounted future cash flows, whenever events occur or circumstances change that may affect the recoverability or the estimated life of long-lived assets. If this evaluation indicates that such cash flows are not expected to fully recover the assets, the assets are written down to their estimated fair value. No significant impairments were recorded in 2010, 2009, or 2008.

Gains and Losses on Debt Extinguishments

Gains and losses on debt extinguishments associated with regulated operations are deferred and amortized over the remaining original amortization period of the debt reacquired, consistent with recovery of costs through regulated rates. PG&E Corporation and the Utility recorded unamortized loss on debt extinguishments, net of gain, of $204 million and $227 million at December 31, 2010 and 2009, respectively. The amortization expense related to this loss was $23 million in 2010, $25 million in 2009, and $26 million in 2008. Deferred gains and losses on debt extinguishments are recorded to other and other noncurrent assets – regulatory assets in the Consolidated Balance Sheets.

Gains and losses on debt extinguishments associated with unregulated operations are fully recognized at the time such debt is reacquired and are reported as a component of interest expense.

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) reports a measure for accumulated changes in equity of an enterprise that result from transactions and other economic events, other than transactions with shareholders. The following table sets forth the after-tax changes in each component of accumulated other comprehensive income (loss):

	Employee Benefit Plans  – Accumulated Other Comprehensive Income (Loss)
(in millions)	2010			2009			2008
Balance at beginning of year	$	(160	)	$	(221	)	$	10
Period change in pension benefits and other benefits:
Unrecognized prior service cost (1)		(29	)		(1	)		37
Unrecognized net gain (loss) (2)		(110	)		363			(1,583	)
Unrecognized net transition obligation (3)		15			15			15
Transfer to regulatory account (4)(5)		82			(316	)		1,300
Balance at end of year	$	(202	)	$	(160	)	$	(221	)

⁽¹⁾ Net of income tax benefit (expense) of $20 million, $1 million, $(27) million for December 31, 2010, 2009, and 2008, respectively.

⁽²⁾ Net of income tax benefit (expense) of $73 million, $(216) million, $1,088 million for December 31, 2010, 2009, and 2008, respectively.

⁽³⁾ Net of income tax benefit (expense) of $(11) million for December 31, 2010, 2009, and 2008.

⁽⁴⁾ Net of income tax benefit (expense) of $(57) million, $218 million, $(894) million for December 31, 2010, 2009, and 2008, respectively.

⁽⁵⁾ Amounts transferred to the pension regulatory asset are probable of recovery from customers in future rates.

There was no material difference between PG&E Corporation’s and the Utility’s accumulated other comprehensive income (loss) for the periods presented above.

Revenue Recognition

The Utility recognizes revenues after persuasive evidence of an arrangement exists, delivery has occurred, or services have been rendered; the price to the customer is fixed or determinable and collectability is reasonably assured. Revenues meet these criteria as the electricity and natural gas services are delivered, and include amounts for services rendered but not yet billed at the end of the period.

The Utility recognizes revenues after the CPUC or the FERC has authorized rate recovery, amounts are objectively determinable and probable of recovery, and amounts will be collected within 24 months. (See Note 3 below.)

The CPUC authorizes most of the Utility’s revenue requirements in its general rate case (“GRC”), which generally occurs every three years. The Utility’s ability to recover revenue requirements authorized by the CPUC in the GRC does not depend on the volume of the Utility’s sales of electricity and natural gas services. Generally, the revenue recognition criteria are met ratably over the year.

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The CPUC also has authorized the Utility to collect additional revenue requirements to recover certain costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; to fund public purpose, demand response, and customer energy efficiency programs; and to recover certain capital expenditures. Generally, the revenue recognition criteria for pass through costs billed to customers are met at the time the costs are incurred.

The Utility’s revenues and earnings also are affected by incentive ratemaking mechanisms that adjust rates depending on the extent the Utility meets certain performance criteria. (See Note 15 below.)

The FERC authorizes the Utility’s revenue requirements in annual transmission owner rate cases. The Utility’s ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is recognized only for amounts billed and unbilled.

In determining whether revenue transactions should be presented net of the related expenses, the Utility considers various factors, including whether the Utility takes title to the product being delivered, has latitude in establishing price for the product, and is subject to the customer credit risk. In January 2001, the California Department of Water Resources (“DWR”) began purchasing electricity to meet the portion of demand of the California investor-owned electric utilities that was not being satisfied from the utilities’ own generation facilities and existing electricity contracts. The Utility acts as a billing and collection agent on behalf of the DWR and does not have any authority to set prices for the energy delivered. The Utility does not assume customer credit risk nor take title to the electricity being delivered to the customer. Therefore, the Utility presents the electricity revenues for amounts delivered to customers net of the cost of electricity delivered by the DWR.

Income Taxes

PG&E Corporation and the Utility use the liability method of accounting for income taxes. Income tax provision (benefit) includes current and deferred income taxes resulting from operations during the year. Investment tax credits are deferred and amortized to income over time. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment. PG&E Corporation amortizes its investment tax credits over the projected investment recovery period or the life of the arrangement for its tax equity arrangements. (See Note 9 below.)

PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position. The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement. The difference between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit.

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

Nuclear Decommissioning Trusts

The Utility’s nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the Nuclear Regulatory Commission (“NRC”) license and release of the property for unrestricted use. The Utility’s nuclear decommissioning costs are recovered from customers through rates.

The Utility classifies its investments held in the nuclear decommissioning trust as “available-for-sale.” As the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at their discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold is determined by specific identification.

Accounting for Derivatives and Hedging Activities

Derivative instruments are recorded in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets at fair value, unless they qualify for the normal purchase and sales exception. Changes in the fair value of derivative instruments are recorded in earnings or, to the extent that they are recoverable through regulated rates, are deferred and recorded in regulatory accounts.

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Derivative instruments may be designated as cash flow hedges when they are entered into in order to hedge variable price risk associated with the purchase of commodities. For cash flow hedges, fair value changes are deferred in accumulated other comprehensive income and recognized in earnings as the hedged transactions occur, unless they are recovered in rates, in which case they are recorded in regulatory accounts.

As of September 30, 2009, the Utility de-designated all cash flow hedge relationships. Due to the regulatory accounting treatment described above, the de-designation of cash flow hedge relationships had no impact on net income or the Consolidated Balance Sheets.

The normal purchase and sales exception to derivative accounting requires, among other things, physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business. Transactions for which the normal purchase and sales exception is elected are not reflected in the Consolidated Balance Sheets at fair value. They are accounted for under the accrual method of accounting. Therefore, expenses are recognized as incurred.

PG&E Corporation and the Utility offset the cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement where the right of offset exists and where PG&E Corporation and the Utility intends to set off. (See Note 10 below.)

Fair Value Measurements

PG&E Corporation and the Utility determine the fair value of certain assets and liabilities based on assumptions that market participants would use in pricing the assets or liabilities. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or the “exit price.” PG&E Corporation and the Utility utilize a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value and give precedence to observable inputs in determining fair value. An instrument’s level within the hierarchy is based on the lowest level of any significant input to the fair value measurement. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). (See Note 11 below.)

Adoption of New Accounting Pronouncements

Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities

On January 1, 2010, PG&E Corporation and the Utility adopted an accounting standards update that changes when and how to determine, or re-determine, whether an entity is a variable interest entity (“VIE”), which could require consolidation. In addition, the accounting standards update replaces the quantitative approach for determining who has a controlling financial interest in a VIE with a qualitative approach and requires ongoing assessments of whether an entity is the primary beneficiary of a VIE. The adoption of the accounting standards update did not have a material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements.

PG&E Corporation and the Utility are required to consolidate any entities that they control. In most cases, control can be determined based on majority ownership or voting interests. However, for certain entities, control is difficult to discern based on ownership or voting interests alone. These entities are referred to as VIEs. A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise has a controlling financial interest if it has the obligation to absorb expected losses or receive expected gains that could potentially be significant to a VIE and the power to direct the activities that are most significant to a VIE’s economic performance. An enterprise that has a controlling financial interest is known as the VIE’s primary beneficiary and is required to consolidate the VIE.

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. In determining whether the Utility has a controlling financial interest in a VIE, the Utility must first assess whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns, as a result of power purchase agreements. This assessment includes an evaluation of how the risks and rewards associated with the power plant’s activities are absorbed by variable interest holders. These VIEs are typically exposed to credit risk, production risk, commodity price risk, and any applicable tax incentive risks, among others. The Utility analyzes the variability in the VIE’s gross margin and the impact of power purchase agreements on the gross margin to determine whether the Utility absorbs variability, resulting in a variable interest. Factors that may be considered when assessing the impact of a power purchase agreement on the VIE’s gross margin include the pricing structure of the power purchase agreement and the cost of inputs and production, which depend on the technology of the power plant.

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For each variable interest, the Utility must also assess whether it has the power to direct the activities of the power plant that most directly impact the VIE’s economic performance. This assessment considers any decision-making rights associated with designing the VIE, any dispatch rights, any operating and maintenance activities, and any re-marketing activities of the power plant after the end of the power purchase agreement with the Utility.

The Utility held a variable interest in several entities that own power plants that generate electricity for sale to the Utility under power purchase agreements. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, and hydroelectric. Under each of these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE. The Utility did not provide any other support to these VIEs, and the Utility’s financial exposure is limited to the amount it pays for delivered electricity and capacity. (See Note 15 below.) The Utility does not have the power to direct the activities that are most significant to these VIE’s economic performance. As a result, the Utility does not have a controlling financial interest in any of these VIEs. Therefore, at December 31, 2010, the Utility was not the primary beneficiary of, and did not consolidate, any of these VIEs.

The Utility continued to consolidate PG&E Energy Recovery Funding LLC (“PERF”) at December 31, 2010, as the Utility is the primary beneficiary of PERF. The Utility has a controlling financial interest in PERF since the Utility is exposed to PERF’s losses and returns through the Utility’s 100% equity investment in PERF and the Utility was involved in the design of PERF, which was an activity that was significant to PERF’s economic performance. The assets of PERF were $897 million at December 31, 2010 and primarily consisted of assets related to energy recovery bonds (“ERBs”), which are included in other noncurrent assets – regulatory assets in the Consolidated Balance Sheets. The liabilities of PERF were $827 million at December 31, 2010 and consisted of energy recovery bonds, which are included in current and noncurrent liabilities in the Consolidated Balance Sheets. (See Note 5 below.) The assets of PERF are only available to settle the liabilities of PERF.

As of December 31, 2010, PG&E Corporation’s affiliates had entered into four tax equity agreements with privately held companies to fund residential and commercial retail solar energy installations. Under these agreements, PG&E Corporation will provide payments of up to $300 million to these companies, and in return, receive the benefits from local rebates, federal investment tax credits or grants, and a share of these companies’ customer payments. PG&E Corporation could be required to pay up to an additional $41 million in the event that its ownership interests are liquidated when in a deficit position. However, PG&E Corporation’s financial exposure from these agreements is generally limited to its lease payments and investment contributions to these companies. As of December 31, 2010, PG&E Corporation had made total payments of $149 million under these agreements primarily related to its lease payments and investment contributions to these companies. These amounts are recorded in other noncurrent assets – other in PG&E Corporation’s Consolidated Balance Sheet. PG&E Corporation holds a variable interest in these companies as a result of these agreements. When determining whether PG&E Corporation is the primary beneficiary of these companies, it evaluated which party has control over their significant economic activities such as designing the companies, vendor selection, construction, customer selection, and re-marketing activities at the end of customer leases. As these activities are under the control of these companies, PG&E Corporation was not the primary beneficiary of, and did not consolidate, any of these companies at December 31, 2010.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Current Regulatory Assets

At December 31, 2010 and 2009, the Utility had current regulatory assets of $599 million and $427 million, respectively, consisting primarily of price risk management regulatory assets. The current portion of price risk management regulatory assets represents the deferral of unrealized losses related to price risk management derivative instruments with terms of one year or less. (See Note 10 below.)

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Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at December 31,
(in millions)	2010		2009
Pension benefits	$	1,759	$	1,386
Deferred income taxes		1,250		1,027
Energy recovery bonds		735		1,124
Utility retained generation		666		737
Environmental compliance costs		450		408
Price risk management		424		346
Unamortized loss, net of gain, on reacquired debt		181		203
Other		381		291
Total long-term regulatory assets	$	5,846	$	5,522

The regulatory asset for pension benefits represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP, which also includes amounts that otherwise would be fully recorded to accumulated other comprehensive loss in the Consolidated Balance Sheets. (See Note 12 below.)

The regulatory assets for deferred income taxes represent deferred income tax benefits previously passed through to customers. The CPUC requires the Utility to pass through certain tax benefits to customers by reducing rates, thereby ignoring the effect of deferred taxes on rates. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover these regulatory assets over average plant depreciation lives of 1 to 45 years.

The regulatory asset for ERBs represents the refinancing of the regulatory asset provided for in the settlement agreement entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11 Settlement Agreement”). (See Note 5 below.) The regulatory asset is amortized over the life of the bonds, consistent with the period over which the related revenues and bond-related expenses are recognized. The Utility expects to fully recover this asset by the end of 2012 when the ERBs mature.

In connection with the Chapter 11 Settlement Agreement, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. The weighted average remaining life of the assets is 13 years.

The regulatory assets for environmental compliance costs represent the portion of estimated environmental remediation costs that the Utility expects to recover in future rates as actual remediation costs are incurred. The Utility expects to recover these costs over the next 32 years. (See Note 15 below.)

Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms in excess of one year. (See Note 10 below.)

The regulatory assets for unamortized loss, net of gain, on reacquired debt represent costs related to debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. These costs are expected to be recovered over the next 16 years, which is the remaining amortization period of the reacquired debt. The Utility expects to fully recover these costs by 2026.

At December 31, 2010 and 2009, “other” primarily consisted of regulatory assets relating to ARO expenses for decommissioning of the Utility’s fossil-fuel generation facilities that are probable of future recovery through the ratemaking process; costs that the Utility incurred in terminating a 30-year power purchase agreement which are being amortized and collected in rates through September 2014; and costs incurred in relation to the Utility’s plan of reorganization under Chapter 11 that became effective in April 2004. Additionally, at December 31, 2010, “other” included removal costs associated with the replacement of old electromechanical meters with SmartMeter™ devices.

In general, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return only on its retained generation regulatory assets and regulatory assets for unamortized loss, net of gain, on reacquired debt.

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Regulatory Liabilities

Current Regulatory Liabilities

At December 31, 2010 and 2009, the Utility had current regulatory liabilities of $81 million and $163 million, respectively, primarily consisting of amounts that the Utility expects to refund to customers for over-collected electric transmission rates and amounts that the Utility expects to refund to electric transmission customers for their portion of settlements the Utility entered into with various electricity suppliers to resolve certain remaining Chapter 11 disputed claims. Current regulatory liabilities are included in current liabilities – other in the Consolidated Balance Sheets.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at December 31,
(in millions)	2010		2009
Cost of removal obligation	$	3,229	$	2,933
Recoveries in excess of ARO		600		488
Public purpose programs		573		508
Other		123		196
Total long-term regulatory liabilities	$	4,525	$	4,125

The regulatory liability for the Utility’s cost of removal obligations represents differences between amounts collected in rates for asset removal costs and the asset removal costs recorded in accordance with GAAP.

The regulatory liability for recoveries in excess of ARO represents differences between amounts collected in rates for decommissioning the Utility’s nuclear power facilities and the ARO expenses recorded in accordance with GAAP. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The regulatory liability for recoveries in excess of ARO also represents the deferral of realized and unrealized gains and losses on those nuclear decommissioning trust assets.

The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose programs costs that are expected to be incurred in the future. The public purpose programs regulatory liabilities primarily consist of revenues collected from customers to pay for costs that the Utility expects to incur in the future under energy efficiency programs designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances and other energy-using products; under the California Solar Initiative program to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties; and under the Self-Generation Incentive program to promote distributed generation technologies installed on the customer’s side of the Utility meter that provide electricity and gas for all or a portion of that customer’s load.

“Other” at December 31, 2010 and 2009 primarily consisted of regulatory liabilities related to the gain associated with the Utility’s acquisition of the permits and other assets related to the Gateway Generating Station as part of a settlement that the Utility entered into with Mirant Corporation and insurance recoveries for hazardous substance remediation.

Regulatory Balancing Accounts

The Utility’s current regulatory balancing accounts represent the amounts expected to be received from or refunded to the Utility’s customers through authorized rate adjustments within the next 12 months. Regulatory balancing accounts that the Utility does not expect to collect or refund in the next 12 months are included in other noncurrent assets – regulatory assets and noncurrent liabilities – regulatory liabilities in the Consolidated Balance Sheets.

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Current Regulatory Balancing Accounts, net

	Receivable (Payable)
	Balance at December 31,
(in millions)	2010		2009
Utility generation	$	303	$	355
Public purpose programs		164		83
Distribution revenue adjustment mechanism		145		152
Gas fixed cost		56		93
Hazardous substance		38		30
Other		143		115
Total regulatory balancing accounts, net	$	849	$	828

The utility generation balancing account is used to record and recover the authorized revenue requirements associated with Utility-owned electric generation, including capital and related non-fuel operating and maintenance expenses. The distribution revenue adjustment mechanism balancing account is used to record and recover the authorized electric distribution revenue requirements and certain other electric distribution-related authorized costs. The Utility’s recovery of these revenue requirements is independent, or “decoupled,” from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers will fluctuate depending on the volume of electricity sales. During periods of more temperate weather, there is generally an under-collection in this balancing account due to lower electricity sales and lower rates. During the warmer months of summer, there is generally an over-collection due to higher rates and electric usage that cause an increase in generation billings.

The public purpose programs balancing accounts primarily track the recovery of the authorized public purpose program revenue requirements and incentive awards earned by the Utility for implementing customer energy efficiency programs. The public purpose programs primarily consist of the energy efficiency programs; low-income energy efficiency programs; research, development, and demonstration programs; and renewable energy programs.

The gas fixed cost balancing account is used to track the recovery of CPUC-authorized gas distribution revenue requirements and certain other gas distribution-related costs. The under-collected or over-collected position of this account is dependent on seasonality and volatility in gas volumes.

The hazardous substance balancing accounts are used to track recoverable hazardous substance clean up costs through the CPUC-approved ratemaking mechanism that authorizes the Utility to recover 90% of hazardous waste remediation costs. The current balance represents eligible remediation costs incurred by the Utility during 2009 that will be recovered through an annual true-up filing with the CPUC in January 2011. (See Note 15 below.)

At December 31, 2010 and 2009, “other” primarily consisted of balancing accounts that track recovery of the authorized revenue requirements and costs related to the SmartMeter^TM advanced metering project.

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NOTE 4: DEBT

Long-Term Debt

The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:

	December 31,
(in millions)	2010			2009
PG&E Corporation
Convertible subordinated notes, 9.50%, due 2010	$	—		$	247
Less: current portion		—			(247	)
Total convertible subordinated notes		—			—
Senior notes, 5.75%, due 2014		350			350
Unamortized discount		(1	)		(2	)
Total senior notes		349			348
Total PG&E Corporation long-term debt, net of current portion		349			348
Utility
Senior notes:
4.20% due 2011		500			500
6.25% due 2013		400			400
4.80% due 2014		1,000			1,000
5.625% due 2017		700			700
8.25% due 2018		800			800
3.50% due 2020		800			—
6.05% due 2034		3,000			3,000
5.80% due 2037		950			700
6.35% due 2038		400			400
6.25% due 2039		550			550
5.40% due 2040		800			550
Less: current portion		(500	)		—
Unamortized discount, net of premium		(52	)		(35	)
Total senior notes		9,348			8,565
Pollution control bonds:
Series 1996 C, E, F, 1997 B, variable rates (1), due 2026 (2)		614			614
Series 1996 A, 5.35%, due 2016 (3)		200			200
Series 2004 A-D, 4.75%, due 2023 (3)		345			345
Series 2008 G and F, 3.75% (4), due 2018 and 2026		—			95
Series 2009 A-D, variable rates (5), due 2016 and 2026 (6)		309			309
Series 2010 E, 2.25%, due 2026 (7)		50			—
Less: current portion		(309	)		(95	)
Total pollution control bonds		1,209			1,468
Total Utility long-term debt, net of current portion		10,557			10,033
Total consolidated long-term debt, net of current portion	$	10,906		$	10,381

⁽¹⁾ At December 31, 2010, interest rates on these bonds and the related loans ranged from 0.26% to 0.31%.

⁽²⁾ Each series of these bonds is supported by a separate direct-pay letter of credit that expires on February 26, 2012. Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains a consent from the issuer to the continuation of the series without a credit facility.

⁽³⁾ The Utility has obtained credit support from insurance companies for these bonds.

⁽⁴⁾ These bonds bore interest at 3.75% per year through September 19, 2010, and were subject to mandatory tender on September 20, 2010. The Utility repurchased these bonds on September 20, 2010.

⁽⁵⁾ At December 31, 2010, interest rates on these bonds and the related loans ranged from 0.22% to 0.29%.

⁽⁶⁾ Each series of these bonds is supported by a separate direct-pay letter of credit that expires on October 29, 2011. The Utility may choose to provide a substitute letter of credit for any series of these bonds, subject to a rating requirement.

⁽⁷⁾ These bonds bear interest at 2.25% per year through April 1, 2012, are subject to mandatory tender on April 2, 2012, and may be remarketed in a fixed or variable rate mode.

PG&E Corporation

Convertible Subordinated Notes

PG&E Corporation issued 16,370,779 shares of common stock upon conversion of the $247 million principal amount of PG&E Corporation’s 9.5% Convertible Subordinated Notes at a conversion price of $15.09 per share between June 23 and June 29, 2010. These notes were no longer outstanding as of December 31, 2010.

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Utility

Senior Notes

On April 1, 2010, the Utility issued $250 million principal amount of 5.8% Senior Notes due March 1, 2037.

On September 15, 2010, the Utility issued $550 million principal amount of 3.5% Senior Notes due October 1, 2020.

On November 18, 2010, the Utility issued $250 million principal amount of 3.5% Senior Notes due October 1, 2020 and $250 million of 5.4% Senior Notes due January 15, 2040.

Pollution Control Bonds

The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility. Under the pollution control bond loan agreements related to the Series 1996 A bonds, the Series 2004 A–D bonds, and the Series 2010 E bonds, the Utility is obligated to pay on the due dates an amount equal to the principal; premium, if any; and interest on these bonds to the trustees for these bonds. With respect to the Series 1996 C, E, and F bonds; the Series 1997 B bonds; and the Series 2009 A–D bonds which currently bear interest at variable rates, the Utility reimburses the letter of credit providers for their payments to the trustee for these bonds, or if a letter of credit provider fails to pay under its respective letter of credit, the Utility is obligated to pay the principal; premium, if any; and interest on those bonds. All payments on the Series 1996 C, E, and F bonds; the Series 1997 B bonds; and the Series 2009 A–D bonds are made through draws on separate direct-pay letters of credit for each series issued by a financial institution.

The Utility has obtained credit support from insurance companies for the Series 1996 A bonds and the Series 2004 A–D bonds such that if the Utility does not pay the principal and interest on any series of these insured bonds, the bond insurer for that series will pay the principal and interest.

On April 8, 2010, the California Infrastructure and Economic Development Bank issued $50 million of tax-exempt pollution control bonds Series 2010 E due November 1, 2026 and loaned the proceeds to the Utility. The proceeds were used to refund the corresponding related series of pollution control bonds issued in 2005 which were repurchased by the Utility in 2008. The Series 2010 E bonds bear interest at 2.25% per year through April 1, 2012 and are subject to mandatory tender on April 2, 2012 at a price of 100% of the principal amount plus accrued interest. Thereafter, this series of bonds may be remarketed in a fixed or variable rate mode. Interest is currently payable semi-annually in arrears on April 1 and October 1.

On September 20, 2010, the Utility repurchased $50 million principal amount of pollution control bonds Series 2008 F and $45 million principal amount of pollution control bonds Series 2008 G that were subject to mandatory tender on the same date. The Utility, as bondholder, will be both the payer and the recipient of principal and interest payments until the bonds are remarketed to the public. As of December 31, 2010, the bonds have not been remarketed to the public.

All of the pollution control bonds were used to finance or refinance pollution control and sewage and solid waste disposal facilities at the Geysers geothermal power plant or at the Utility’s Diablo Canyon nuclear power plant and were issued as “exempt facility bonds” within the meaning of the Internal Revenue Code of 1954, as amended. In 1999, the Utility sold the Geysers geothermal power plant to Geysers Power Company, LLC pursuant to purchase and sale agreements stating that Geysers Power Company, LLC will use the bond-financed facilities solely as pollution control facilities. The Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities.

Repayment Schedule

PG&E Corporation’s and the Utility’s combined aggregate principal repayment amounts of long-term debt at December 31, 2010 are reflected in the table below:

(in millions, except interest rates)	2011			2012			2013			2014			2015		Thereafter			Total
Long-term debt:
PG&E Corporation
Average fixed interest rate		—			—			—			5.75	%		—		—			5.75	%
Fixed rate obligations	$	—		$	—		$	—		$	350		$	—	$	—		$	350
Utility
Average fixed interest rate		4.20	%		2.25	%		6.25	%		4.80	%		—		5.85	%		5.67	%
Fixed rate obligations	$	500		$	50	(2)	$	400		$	1,000		$	—	$	8,545		$	10,495
Variable interest rate as of December 31, 2010		0.27	%		0.28	%		—			—			—		—			0.28	%
Variable rate obligations	$	309	(1)	$	614	(3)	$	—		$	—		$	—	$	—		$	923
Less: current portion		(809	)		—			—			—			—		—			(809	)
Total consolidated long-term debt	$	—		$	664		$	400		$	1,350		$	—	$	8,545		$	10,959

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⁽¹⁾ These bonds, due from 2016 through 2026, are backed by direct-pay letters of credit that expire on October 29, 2011. The bonds will be subject to a mandatory redemption unless the letter of credit is extended or replaced or the issuer consents to the continuation of these series without a credit facility. Accordingly, the bonds have been classified for repayment purposes in 2011.

⁽²⁾ These bonds, due in 2026, are subject to mandatory tender on April 2, 2012 and may be remarketed in a fixed or variable rate mode. Accordingly, the bonds have been classified for repayment purposes in 2012.

⁽³⁾ These bonds, due in 2026, are backed by direct-pay letters of credit that expire on February 26, 2012. The bonds will be subject to a mandatory redemption unless the letters of credit are extended or replaced. Accordingly, the bonds have been classified for repayment purposes in 2012.

Credit Facilities and Short-Term Borrowings

The following table summarizes PG&E Corporation’s and the Utility’s borrowings on outstanding credit facilities at December 31, 2010:

(in millions)	Termination Date	Facility Limit			Letters of Credit Outstanding		Cash Borrowings		Commercial Paper Backup		Availability
PG&E Corporation	February 2012	$	187	(1)	$	—	$	—		N/A	$	187
Utility	February 2012		1,940	(2)		329		—	$	603		1,008
Utility	February 2012		750	(3)		N/A		—		—		750
Total credit facilities		$	2,877		$	329	$	—	$	603	$	1,945

⁽¹⁾ Includes a $87 million sublimit for letters of credit and a $100 million commitment for “swingline” loans, defined as loans that are made available on a same-day basis and are repayable in full within 30 days.

⁽²⁾ Includes a $921 million sublimit for letters of credit and a $200 million commitment for swingline loans.

⁽³⁾ Includes a $75 million commitment for swingline loans.

PG&E Corporation

Revolving credit facility

PG&E Corporation has a $187 million revolving credit facility with a syndicate of lenders that expires on February 26, 2012. Borrowings under the revolving credit facility and letters of credit may be used for working capital and other corporate purposes. PG&E Corporation can, at any time, repay amounts outstanding in whole or in part. At PG&E Corporation’s request and at the sole discretion of each lender, the revolving credit facility may be extended for additional periods. PG&E Corporation has the right to increase, in one or more requests given no more than once a year, the aggregate facility by up to $100 million provided that certain conditions are met. The fees and interest rates that PG&E Corporation pays under the revolving credit facility vary depending on the Utility’s unsecured debt ratings issued by Standard & Poor’s (“S&P”) ratings service and Moody’s Investors Service (“Moody’s”).

The revolving credit facility includes usual and customary covenants for credit facilities of this type, including covenants limiting liens, mergers, sales of all or substantially all of PG&E Corporation’s assets, and other fundamental changes. In general, the covenants, representations, and events of default mirror those in the Utility’s revolving credit facility, discussed below. In addition, the revolving credit facility requires that PG&E Corporation maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% and that PG&E Corporation own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting securities of the Utility. At December 31, 2010, PG&E Corporation met both of these tests.

Utility

Revolving credit facilities

The Utility has a $1.9 billion revolving credit facility with a syndicate of lenders that expires on February 26, 2012. Borrowings under the revolving credit facility and letters of credit are used primarily for liquidity and to provide credit enhancements to counterparties for natural gas and energy procurement transactions.

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On June 8, 2010, the Utility entered into a $750 million unsecured revolving credit agreement with a syndicate of lenders. Of the total credit capacity, $500 million was used to replace the $500 million Floating Rate Senior Notes that matured on June 10, 2010. The aggregate facility of $750 million includes a $75 million commitment for swingline loans, or loans that are made available on a same-day basis and are repayable in full within 30 days. The Utility can, at any time, repay amounts outstanding in whole or in part. The credit agreement expires on February 26, 2012, unless extended for additional periods at the Utility’s request and at the sole discretion of each lender.

Borrowings under the credit agreement (other than swingline loans) will bear interest based, at the Utility’s election, at (1) London Interbank Offered Rate (“LIBOR”) plus an applicable margin or (2) the base rate, which will equal the higher of the (i) administrative agent’s announced base rate, (ii) 0.5% above the federal funds rate, or (iii) the one-month LIBOR plus an applicable margin. Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods. The Utility also will pay a facility fee on the total commitments of the lenders under the credit agreement. The applicable margin for LIBOR loans and the facility fee will be based on the Utility’s senior unsecured, non-credit enhanced debt ratings issued by S&P and Moody’s. Facility fees are payable quarterly in arrears.

The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facilities so that liquidity from the revolving credit facility is available to repay outstanding commercial paper.

The revolving credit facilities include usual and customary covenants for credit facilities of this type, including covenants limiting liens to those permitted under the senior note indenture, mergers, sales of all or substantially all of the Utility’s assets, and other fundamental changes. Both the $750 million and $1.9 billion revolving credit facilities require that the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of, at most, 65% as of the end of each fiscal quarter. At December 31, 2010, the Utility met this ratio test.

Commercial Paper Program

The Utility has a $1.75 billion commercial paper program, the borrowings from which are used primarily to cover fluctuations in cash flow requirements. Liquidity support for these borrowings is provided by available capacity under the Utility’s revolving credit facilities, as described above. The commercial paper may have maturities up to 365 days and ranks equally with the Utility’s other unsubordinated and unsecured indebtedness. Commercial paper notes are sold at an interest rate dictated by the market at the time of issuance. At December 31, 2010, the average yield was 0.51%.

Other Short-term Borrowings

On October 12, 2010, the Utility issued $250 million principal amount of Floating Rate Senior Notes due October 11, 2011. The interest rate for the Floating Rate Senior Notes is equal to the three-month LIBOR plus 0.58% and will reset quarterly beginning on January 11, 2011. At December 31, 2010, the interest rate on the Floating Rate Senior Notes was 0.87%. On January 11, 2011, the interest rate was reset to 0.88%.

NOTE 5: ENERGY RECOVERY BONDS

In 2005 PERF issued two separate series of ERBs in the aggregate amount of $2.7 billion to refinance a regulatory asset that the Utility recorded in connection with the Chapter 11 Settlement Agreement. The proceeds of the ERBs were used by PERF to purchase from the Utility the right, known as “recovery property,” to be paid a specified amount from a dedicated rate component (“DRC”) to be collected from the Utility’s electricity customers. DRC charges are authorized by the CPUC under state legislation and will be paid by the Utility’s electricity customers until the ERBs are fully retired. Under the terms of a recovery property servicing agreement, DRC charges are collected by the Utility and remitted to PERF for payment of principal, interest, and miscellaneous expenses associated with the bonds.

The first series of ERBs issued on February 10, 2005 included five classes aggregating to a $1.9 billion principal amount with scheduled maturities ranging from September 25, 2006 to December 25, 2012. Interest rates on the remaining two outstanding classes are 4.37% for the earlier maturing class and 4.47% for the later maturing class. The proceeds of the first series of ERBs were paid by PERF to the Utility and were used by the Utility to refinance the remaining unamortized after-tax balance of the settlement regulatory asset. The second series of ERBs, issued on November 9, 2005, included three classes aggregating to an $844 million principal amount, with scheduled maturities ranging from June 25, 2009 to December 25, 2012. Interest rates on the remaining two classes are 5.03% for the earlier maturing class and 5.12% for the later maturing class. The proceeds of the second series of ERBs were paid by PERF to the Utility to pre-fund the Utility’s tax liability that will be due as the Utility collects the DRC charges from customers.

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The total amount of ERB principal outstanding was $827 million at December 31, 2010 and $1.2 billion at December 31, 2009. The scheduled principal repayments for ERBs are reflected in the table below:

(in millions)	2011			2012			Total
Utility
Average fixed interest rate		4.59	%		4.66	%			4.63	%
Energy recovery bonds	$	404		$	423			$	827

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

NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation

Of the 395,227,205 shares of PG&E Corporation common stock outstanding at December 31, 2010, 475,880 shares were granted as restricted stock under the PG&E Corporation Long-Term Incentive Program and the 2006 Long-Term Incentive Plan (“2006 LTIP”) and 5,105,505 shares were issued for the accounts of participants in PG&E Corporation’s 401(k) plan and Dividend Reinvestment and Stock Purchase Plan (“DRSPP”). In addition, between June 23 and June 29, 2010, PG&E Corporation issued 16,370,779 shares of common stock upon conversion of the $247 million principal amount of Convertible Subordinated Notes. (See Note 4 above.)

On November 4, 2010, PG&E Corporation entered into an Equity Distribution Agreement pursuant to which PG&E Corporation’s sales agents may offer and sell, from time to time, PG&E Corporation common stock having an aggregate gross offering price of up to $400 million. Sales of the shares are made by means of ordinary brokers’ transactions on the New York Stock Exchange, or in such other transactions as agreed upon by PG&E Corporation and the sales agents and in conformance with applicable securities laws. As of December 31, 2010, PG&E Corporation had issued 2,357,796 shares of its common stock pursuant to the Equity Distribution Agreement for cash proceeds of $110 million, net of fees and commissions paid of $1 million.

Utility

As of December 31, 2010, PG&E Corporation held all of the Utility’s outstanding common stock.

Dividends

The Boards of Directors of PG&E Corporation and the Utility have each adopted a dividend policy. Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid.

PG&E Corporation and the Utility each have revolving credit facilities that require the company to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%. This covenant, along with the CPUC’s requirement for the Utility to maintain the 52% equity component of its capital structure, are considered to be restrictions on the payment of dividends. Based on the calculation of these ratios for each company, no amount of PG&E Corporation’s retained earnings and $5.3 billion of the Utility’s retained earnings were restricted at December 31, 2010.

In addition, the Utility was required to maintain at least $9.7 billion of its net assets as equity in order to maintain the capital structure of at least 52% equity at December 31, 2010. As a result, $9.7 billion of the Utility’s net assets are restricted and may not be transferred to PG&E Corporation in the form of cash dividends.

The Boards of Directors of PG&E Corporation and the Utility declare dividends quarterly. On December 15, 2010, the Board of Directors of PG&E Corporation declared a quarterly dividend of $0.455 per share, totaling $183 million, which was paid on January 15, 2011 to shareholders of record on December 31, 2010.

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Long-Term Incentive Plan

The 2006 LTIP permits the award of various forms of incentive awards, including stock options, stock appreciation rights, restricted stock awards, restricted stock units, performance shares, deferred compensation awards, and other stock-based awards, to eligible employees of PG&E Corporation and its subsidiaries. Non-employee directors of PG&E Corporation are also eligible to receive restricted stock and either stock options or restricted stock units under the formula grant provisions of the 2006 LTIP. A maximum of 12 million shares of PG&E Corporation common stock (subject to adjustment for changes in capital structure, stock dividends, or other similar events) has been reserved for issuance under the 2006 LTIP, of which 7,856,348 shares were available for award at December 31, 2010.

Awards made under the PG&E Corporation LTIP before December 31, 2005 and still outstanding continue to be governed by the terms and conditions of the PG&E Corporation LTIP.

PG&E Corporation and the Utility use an estimated annual forfeiture rate of 2.5% for stock options and restricted stock and 2% for performance shares, based on historic forfeiture rates, for purposes of determining compensation expense for share-based incentive awards. The following table provides a summary of total compensation expense for PG&E Corporation and the Utility for share-based incentive awards for 2010, 2009, and 2008:

(in millions)	2010		2009		2008
Stock Options	$	—	$	—	$	2
Restricted Stock		14		9		22
Restricted Stock Units		9		11		—
Performance Shares:
Liability Awards		22		37		33
Equity Awards		11		—		—
Total Compensation Expense (pre-tax)	$	56	$	57	$	57
Total Compensation Expense (after-tax)	$	33	$	34	$	34

There were no significant stock-based compensation costs capitalized during 2010, 2009 and 2008. There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Stock Options

The exercise price of stock options granted under the 2006 LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant. Stock options generally have a 10-year term and vest over four years of continuous service, subject to accelerated vesting in certain circumstances.

The following table summarizes total intrinsic value (fair market value of PG&E Corporation’s common stock less exercise price) of options exercised:

	PG&E Corporation
(in millions)	2010		2009		2008
Intrinsic value of options exercised	$	15	$	18	$	13

The tax benefit from stock options exercised totaled $0.5 million, $6 million, and $4 million for 2010, 2009, and 2008 respectively.

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The following table summarizes stock option activity for 2010:

Options	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1		1,975,341		$	23.99
Granted		1,742			42.97
Exercised		(605,585	)		22.67
Forfeited or expired		(1,587	)		30.13
Outstanding at December 31		1,369,911			25.16		2.76	$	31,068,628
Expected to vest at December 31		21,401			37.77		7.89	$	215,584
Exercisable at December 31		1,348,510		$	24.96		2.68	$	30,853,045

As of December 31, 2010, there was less than $1 million of total unrecognized compensation cost related to outstanding stock options.

Restricted Stock

During 2010, PG&E Corporation awarded 10,540 shares of restricted common stock to eligible participants under the 2006 LTIP. The terms of the restricted stock awarded provide that the shares will vest over a five year period. Although the recipients of restricted stock possess voting rights, they may not sell or transfer their shares until the shares vest.

Prior to 2010, PG&E Corporation also awarded stock to eligible employees under the 2006 LTIP. The terms of these restricted stock award agreements provide that 60% of the shares will vest over a period of three years at the rate of 20% per year. If PG&E Corporation’s annual total shareholder return (“TSR”) is in the top quartile of its comparator group, as measured for the three immediately preceding calendar years, the restrictions on the remaining 40% of the shares will lapse in the third year. If PG&E Corporation’s TSR is not in the top quartile for that period, then the restrictions on the remaining 40% of the shares will lapse in the fifth year. Compensation expense related to the portion of the restricted stock award that is subject to conditions based on TSR is recognized over the shorter of the requisite service period and three years. Dividends declared on restricted stock are paid to recipients only when the restricted stock vests.

The weighted average grant-date fair value per-share of restricted stock granted during 2010, 2009, and 2008 was $42.97, $35.53, and $37.91, respectively. The total fair value of restricted stock that vested during 2010, 2009, and 2008 was $8 million, $24 million, and $19 million, respectively. The tax benefit from restricted stock that vested during 2010, 2009, and 2008 was not material.

The following table summarizes restricted stock activity for 2010:

	Number of Shares  of Restricted Stock			Weighted Average Grant- Date Fair Value
Nonvested at January 1		670,552		$	41.11
Granted		10,540		$	42.97
Vested		(189,976	)	$	41.70
Forfeited		(15,236	)	$	42.52
Nonvested at December 31		475,880		$	40.87

As of December 31, 2010, there was less than $1 million of total unrecognized compensation cost relating to restricted stock.

Restricted Stock Units

Beginning January 1, 2009, PG&E Corporation primarily awarded restricted stock units (“RSU”) instead of restricted stock as permitted by the 2006 LTIP. RSUs are hypothetical shares of stock that will generally vest in 20% increments on the first business day of March in year one, two, and three, with the remaining 40% vesting on the first business day of March in year four. Each vested RSU is settled for one share of PG&E Corporation common stock. Additionally, upon settlement, RSU recipients receive payment for the amount of dividend equivalents associated with the vested RSUs that have accrued since the date of grant.

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The weighted average grant-date fair value per RSU granted during 2010 and 2009 was $42.97 and $35.53, respectively. The total fair value of RSUs that vested during 2010 and 2009 was $5 million and less than $1 million, respectively. As of December 31, 2010, $21 million of total unrecognized compensation costs related to nonvested RSUs are expected to be recognized over the remaining weighted average period of 2.70 years.

The following table summarizes RSU activity for 2010:

	Number of Restricted Stock Units			Weighted Average Grant- Date Fair Value
Nonvested at January 1		664,992		$	35.78
Granted		640,060		$	42.97
Vested		(125,651	)	$	35.60
Forfeited		(25,005	)	$	37.61
Nonvested at December 31		1,154,396		$	39.74

Performance Shares

On March 10, 2010, PG&E Corporation granted 605,275 contingent performance shares to eligible employees under the 2006 LTIP. Unlike performance shares awarded in prior periods (see below), which settle in cash, 2010 grants will be settled in PG&E Corporation common stock and are classified as share-based equity awards. Performance shares granted and outstanding prior to 2010 will not be modified and will continue to be paid and settled in cash. The vesting of the performance shares granted in 2010 is dependent upon three years of continuous service. Additionally the amount of common stock that recipients are entitled to receive, if any, will be determined based on PG&E Corporation’s TSR relative to the performance of a specified group of peer companies for the applicable three year performance period. Total compensation expense for these shares is based on the grant-date fair value, which is determined using a Monte Carlo simulation valuation model. Performance share expense is recognized ratably over the requisite service period based on the fair values determined, except for the expense attributable to awards granted to retirement-eligible participants, which is recognized on the date of grant. Dividend equivalents on equity-classified awards, if any, will be paid in cash upon vesting date based on the amount of common stock awarded.

For performance shares classified as equity awards, the following table summarizes activity for 2010:

	Number of Performance Shares			Weighted Average Grant- Date Fair Value
Nonvested at January 1		—
Granted		616,990		$	35.60
Vested		—
Forfeited		(7,020	)	$	35.60
Nonvested at December 31		609,970		$	35.60

As of December 31, 2010, $10 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.22 years.

Prior to 2010, PG&E Corporation awarded performance shares to eligible participants under the 2006 LTIP as hypothetical shares of common stock that vest at the end of a three-year period and are settled in cash based on the performance of PG&E Corporation’s TSR. Upon vesting, the amount of cash that recipients are entitled to receive, if any, is determined by multiplying the number of vested performance shares by the average closing price of PG&E Corporation common stock for the last 30 calendar days in the three-year performance period. This result is then adjusted based on PG&E Corporation’s TSR relative to the performance of a specified group of peer companies for the applicable three-year performance period. These outstanding performance shares are classified as a liability because the performance shares can only be settled in cash. During each reporting period compensation expense recognized for performance shares will fluctuate based on PG&E Corporation’s common stock price and its TSR relative to its comparator group. As of December 31, 2010 and 2009, $68 million and $63 million, respectively, had been accrued as the performance share liability for PG&E Corporation.

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For performance shares classified as liability awards, the following table summarizes activity for 2010:

	Number of Performance Shares			Weighted Average Fair Value
Nonvested at January 1		1,547,598		$	55.98
Granted		—
Vested		(387,019	)	$	43.06
Forfeited		(23,089	)	$	56.18
Nonvested at December 31		1,137,490		$	60.37

For performance shares classified as liability awards, the total intrinsic value of amounts settled during 2010, 2009, and 2008 was $17 million, $21 million, and $7 million, respectively.

NOTE 7: PREFERRED STOCK

PG&E Corporation

PG&E Corporation has authorized 80 million shares of no par value preferred stock and 5 million shares of $100 par value preferred stock, which may be issued as redeemable or nonredeemable preferred stock. No preferred stock of PG&E Corporation has been issued to date.

Utility

The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value preferred stock. The Utility specifies that 5,784,825 shares of the $25 par value preferred stock authorized are designated as nonredeemable preferred stock without mandatory redemption provisions. All remaining shares of preferred stock may be issued as redeemable or nonredeemable preferred stock.

The following table summarizes the Utility’s outstanding preferred stock without mandatory redemption provisions at December 31, 2010 and 2009:

(in millions, except share amounts, redemption price, and par value)	Shares Outstanding		Redemption Price		Balance
Nonredeemable $25 par value preferred stock
5.00% Series		400,000		N/A	$	10
5.50% Series		1,173,163		N/A		30
6.00% Series		4,211,662		N/A		105
Total nonredeemable preferred stock		5,784,825			$	145
Redeemable $25 par value preferred stock
4.36% Series		418,291	$	25.75	$	11
4.50% Series		611,142		26.00		15
4.80% Series		793,031		27.25		20
5.00% Series		1,778,172		26.75		44
5.00% Series A		934,322		26.75		23
Total redeemable preferred stock		4,534,958			$	113
Preferred stock					$	258

Holders of the Utility’s nonredeemable preferred stock have rights to annual dividends ranging from $1.25 to $1.50 per share. The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2010, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.

Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. During each of

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2010, 2009, and 2008, the Utility paid $14 million of dividends on preferred stock. On December 15, 2010, the Board of Directors of the Utility declared a cash dividend on its outstanding series of preferred stock totaling $4 million that was paid on February 15, 2011 to preferred shareholders of record on January 31, 2011. On February 16, 2011, the Board of Directors of the Utility declared a cash dividend on its outstanding series of preferred stock, payable on May 15, 2011, to shareholders of record on April 29, 2011.

NOTE 8: EARNINGS PER SHARE

PG&E Corporation’s earnings per common share (“EPS”) is calculated utilizing the “two-class” method by dividing the sum of distributed earnings to common shareholders and undistributed earnings allocated to common shareholders by the weighted average number of common shares outstanding during the period. In applying the two-class method, undistributed earnings are allocated to both common shares and participating securities. PG&E Corporation’s Convertible Subordinated Notes met the criteria of participating securities as the holders were entitled to receive dividends similar to holders of common stock.

As of June 29, 2010, all of PG&E Corporation’s Convertible Subordinated Notes had been converted into common stock. Therefore, there were no participating securities outstanding at December 31, 2010. (See Note 4 above.)

The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating basic EPS:

	Year Ended December 31,
(in millions, except per share amounts)	2010		2009		2008
Basic
Income available for common shareholders	$	1,099	$	1,220	$	1,338
Less: distributed earnings to common shareholders		706		621		560
Undistributed earnings		393		599		778
Less: undistributed earnings from discontinued operations		—		—		154
Undistributed earnings from continuing operations	$	393	$	599	$	624
Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders	$	706	$	621	$	560
Undistributed earnings allocated to common shareholders – continuing operations		385		573		592
Undistributed earnings allocated to common shareholders – discontinued operations		—		—		146
Total common shareholders earnings	$	1,091	$	1,194	$	1,298
Weighted average common shares outstanding, basic		382		368		357
Convertible subordinated notes		8		17		19
Weighted average common shares outstanding and participating securities		390		385		376
Net earnings per common share, basic
Distributed earnings, basic (1)	$	1.85	$	1.69	$	1.57
Undistributed earnings – continuing operations, basic		1.01		1.56		1.66
Undistributed earnings – discontinued operations, basic		—		—		0.41
Total	$	2.86	$	3.25	$	3.64

⁽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.

In calculating diluted EPS during the period PG&E Corporation’s Convertible Subordinated Notes were outstanding, PG&E Corporation applied the “if-converted” method to reflect the dilutive effect of the Convertible Subordinated Notes to the extent that the impact is dilutive when compared to basic EPS. In addition, PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS.

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The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating diluted EPS:

	Year ended
	December 31,
(in millions, except per share amounts)	2010		2009
Diluted
Income available for common shareholders	$	1,099	$	1,220
Add earnings impact of assumed conversion of participating securities:
Interest expense on convertible subordinated notes, net of tax		8		15
Unrealized loss on embedded derivative, net of tax		—		2
Income available for common shareholders and assumed conversion	$	1,107	$	1,237
Weighted average common shares outstanding, basic		382		368
Add incremental shares from assumed conversions:
Convertible subordinated notes		8		17
Employee share-based compensation		2		1
Weighted average common shares outstanding, diluted		392		386
Total earnings per common share, diluted	$	2.82	$	3.20

The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating diluted EPS:

	Year ended
	December 31,
(in millions, except per share amounts)	2008
Diluted
Income available for common shareholders	$	1,338
Less: distributed earnings to common shareholders		560
Undistributed earnings		778
Less: undistributed earnings from discontinued operations		154
Undistributed earnings from continuing operations	$	624
Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders	$	560
Undistributed earnings allocated to common shareholders – continuing operations		593
Undistributed earnings allocated to common shareholders – discontinued operations		146
Total common shareholders earnings	$	1,299
Weighted average common shares outstanding, basic		357
Convertible subordinated notes		19
Weighted average common shares outstanding and participating securities, basic		376
Weighted average common shares outstanding, basic		357
Employee share-based compensation		1
Weighted average common shares outstanding, diluted		358
Convertible subordinated notes		19
Weighted average common shares outstanding and participating securities, diluted		377
Net earnings per common share, diluted
Distributed earnings, diluted	$	1.56
Undistributed earnings – continuing operations, diluted		1.66
Undistributed earnings – discontinued operations, diluted		0.41
Total earnings per common share, diluted	$	3.63

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For each of the periods presented above, the calculation of outstanding shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

NOTE 9: INCOME TAXES

The significant components of income tax provision (benefit) for continuing operations were as follows:

	PG&E Corporation									Utility
	Year Ended December 31,
	2010			2009			2008			2010			2009			2008
(in millions)
Current:
Federal	$	(12	)	$	(747	)	$	(268	)	$	(54	)	$	(696	)	$	(188	)
State		130			(41	)		33			134			(45	)		24
Deferred:
Federal		525			1,161			604			589			1,139			596
State		(91	)		92			62			(90	)		89			62
Tax credits		(5	)		(5	)		(6	)		(5	)		(5	)		(6	)
Income tax provision	$	547		$	460		$	425		$	574		$	482		$	488

The following describes net deferred income tax liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
	2010		2009		2010		2009
(in millions)
Deferred income tax assets:
Reserve for damages	$	222	$	138	$	222	$	138
Environmental reserve		242		227		242		227
Compensation		345		338		305		304
Net operating loss carry forward		327		—		270		—
Other		207		184		178		180
Total deferred income tax assets	$	1,343	$	887	$	1,217	$	849
Deferred income tax liabilities:
Regulatory balancing accounts	$	1,116	$	1,340	$	1,116	$	1,340
Property related basis differences		5,236		4,036		5,234		4,032
Income tax regulatory asset		509		418		509		418
Other		142		157		135		157
Total deferred income tax liabilities	$	7,003	$	5,951	$	6,994	$	5,947
Total net deferred income tax liabilities	$	5,660	$	5,064	$	5,777	$	5,098
Classification of net deferred income tax liabilities:
Included in current liabilities	$	113	$	332	$	118	$	334
Included in noncurrent liabilities		5,547		4,732		5,659		4,764
Total net deferred income tax liabilities	$	5,660	$	5,064	$	5,777	$	5,098

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

	PG&E Corporation									Utility
	Year Ended December 31,
	2010			2009			2008			2010			2009			2008
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit)		0.7			1.6			3.1			1.0			1.4			3.3
Effect of regulatory treatment of fixed asset differences		(3.1	)		(2.7	)		(3.2	)		(3.0	)		(2.6	)		(3.1	)
Tax credits		(0.4	)		(0.5	)		(0.5	)		(0.4	)		(0.5	)		(0.5	)
IRS audit settlements		0.1			(4.5	)		(7.1	)		(0.2	)		(4.2	)		(4.1	)
Other, net		0.9			(1.5	)		(0.9	)		1.5			(1.3	)		(1.7	)
Effective tax rate		33.2	%		27.4	%		26.4	%		33.9	%		27.8	%		28.9	%

Unrecognized tax benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation									Utility
	2010			2009			2008			2010			2009			2008
(in millions)
Balance at beginning of year	$	673		$	75		$	209		$	652		$	37		$	94
Additions for tax position taken during a prior year		27			4			—			27			4			—
Additions for tax position taken during the current year		89			624			43			87			623			20
Settlements		(55	)		(27	)		(177	)		(54	)		(12	)		(77	)
Reductions for tax position taken during a prior year		(20	)		(3	)		—			—			—			—
Balance at end of year	$	714		$	673		$	75		$	712		$	652		$	37

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2010 for PG&E Corporation and the Utility is $39 million, with the remaining balance representing the probable deferral of taxes to later years. PG&E Corporation and the Utility do not expect that the total unrecognized tax benefits would significantly change within the next 12 months.

PG&E Corporation and the Utility recognize accrued interest and penalties related to unrecognized tax benefits as income tax expense in the Consolidated Statements of Income. Interest income net of penalties recognized in income tax expense by PG&E Corporation in 2010, 2009, and 2008 was $3 million, $19 million, and $24 million, respectively. Interest income net of penalties recognized in income tax expense by the Utility in 2010, 2009, and 2008 was $3 million, $14 million, and $11 million, respectively.

As of December 31, 2010, PG&E Corporation and the Utility had accrued interest income of $8 million. As of December 31, 2009, PG&E Corporation and the Utility had accrued interest expense and penalties of $11 million and $12 million, respectively.

Federal subsidy for Medicare Part D

PG&E Corporation and the Utility receive a federal subsidy for maintaining a retiree medical benefit plan with prescription drug benefits that is actuarially equivalent to Medicare Part D. For federal income tax purposes, the subsidy was deductible when contributed to the benefit plan maintained for these benefits. On March 30, 2010, federal healthcare legislation was signed eliminating the deduction for subsidy contributions after 2012. As a result, PG&E Corporation and the Utility recognized an expense of $19 million in 2010 to reverse previously recognized federal tax benefits (recorded as an increase to income tax provision and a reduction to deferred income tax assets for subsidy amounts included in the calculation of accrued retiree medical benefit obligation).

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Tax settlements and years that remain subject to examination

On September 29, 2010, PG&E Corporation received the Internal Revenue Service (“IRS”) examination report for the 2005 to 2007 audit years and resolved all matters except for a few items that will be discussed with the IRS Appeals office. Included in the 2005 to 2007 audit was the resolution of the change in accounting method related to the capitalization of indirect service costs for those years. As a result, PG&E Corporation recorded a $25 million reduction to income tax expense during 2010.

In tax year 2008, PG&E Corporation began participating in the Compliance Assurance Process (“CAP”), a real-time IRS audit intended to expedite resolution of tax matters. The CAP audit culminates with a letter from the IRS indicating their acceptance of the return. The IRS partially accepted the 2008 return, withholding two issues for further review. The most significant of these relates to a tax accounting method change filed by PG&E Corporation to accelerate the amount of deductible repairs. While the IRS approved PG&E Corporation’s request for a change in method, the IRS will audit the methodology to determine the proper deduction. This audit has not progressed significantly because the IRS is working with the utility industry to resolve this matter in a consistent manner for all utilities before auditing individual companies. On December 14, 2010 the IRS accepted PG&E Corporation’s 2009 tax return without change.

In 2009, PG&E Corporation recognized an income tax benefit of $56 million from settling a claim with the IRS related to 1998 and 1999. Additionally during 2009, PG&E Corporation recognized $12 million in California benefits, of which $10 million was attributable to this settlement and $2 million was attributable to the 2001–2004 IRS settlement. (The 2001–2004 IRS settlement resulted in a $154 million tax benefit related to National Energy & Gas Transmission, Inc. (“NEGT”) and was recorded as discontinued operations in 2008.) PG&E Corporation received total cash refunds of $605 million in 2009 related to these settlements.

The California Franchise Tax Board is auditing PG&E Corporation’s 2004 and 2005 combined California income tax returns, as well as the 1997-2007 amended income tax returns reflecting IRS settlements for these years and claim filings that apply only to California. It is uncertain when the California Franchise Tax Board will complete the audits.

PG&E Corporation believes that the final resolution of the federal and California audits will not have a material adverse impact on its financial condition or results of operations. PG&E Corporation is neither under audit nor subject to any material risk in any other jurisdiction.

Loss carry forwards

As of December 31, 2010 and 2009, PG&E Corporation has $24 million and $25 million, respectively, of federal and California capital loss carry forwards based on filed tax returns, of which approximately $9 million will expire if not used by December 31, 2011. For all periods presented, PG&E Corporation has provided a full valuation allowance against its deferred income tax assets for capital loss carry forwards.

The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (the “Tax Relief Act”) Federal legislation that was signed into law on December 17, 2010, provides for full expensing of qualified property, plant, and equipment placed in service from September 9, 2010 to December 31, 2011 for tax purposes. The Tax Relief Act increased PG&E Corporation’s federal net operating loss carry forwards. As of December 31, 2010, PG&E Corporation has approximately $540 million of federal net operating loss carry forwards and $45 million of tax credit carry forwards, which will expire between 2029 and 2030. In addition, PG&E Corporation has approximately $46 million of loss carry forwards related to charitable contributions, which will expire between 2014 and 2015. PG&E Corporation believes it is more likely than not the tax benefits associated with the federal operating loss and tax credit can be realized within the carry forward periods, therefore no valuation allowance was recognized as of December 31, 2010. The amount of federal net operating loss carry forwards for which a tax benefit from employee stock plans would be recorded in additional paid-in capital was approximately $9 million as of December 31, 2010.

NOTE 10: DERIVATIVES AND HEDGING ACTIVITIES

Use of Derivative Instruments

The Utility faces market risk primarily related to electricity and natural gas commodity prices. All of the Utility’s risk management activities involving derivatives reduce the volatility of commodity costs on behalf of its customers. The CPUC allows the Utility to charge customer rates designed to recover the Utility’s reasonable costs of providing services, including the cost to obtain and deliver electricity and natural gas.

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The Utility uses both derivative and non-derivative contracts in managing its customers’ exposure to commodity-related price risk, including:

• forward contracts that commit the Utility to purchase a commodity in the future;

• swap agreements that require payments to or from counterparties based upon the difference between two prices for a predetermined contractual quantity;

• option contracts that provide the Utility with the right to buy a commodity at a predetermined price; and

• futures contracts that are exchange-traded contracts committing the Utility to make a cash settlement at a specified price and future date.

These instruments are not held for speculative purposes and are subject to certain regulatory requirements.

Commodity-Related Price Risk

Commodity-related price risk management activities that meet the definition of a derivative are recorded at fair value on the Consolidated Balance Sheets. As long as the ratemaking mechanisms discussed above remain in place and the Utility’s risk management activities are carried out in accordance with CPUC directives, the Utility expects to fully recover from customers, in rates, all costs related to commodity-related price risk-related derivative instruments. Therefore, all unrealized gains and losses associated with the change in fair value of these derivative instruments are deferred and recorded within the Utility’s regulatory assets and liabilities on the Consolidated Balance Sheets. (See Note 3 above.) Net realized gains or losses on derivative instruments related to price risk for commodities are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from customers.

The Utility elects the normal purchase and sale exception for qualifying commodity-related derivative instruments. Derivative instruments that require physical delivery, are probable of physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered are eligible for the normal purchase and sale exception. The fair value of instruments that are eligible for the normal purchase and sales exception are not reflected in the Consolidated Balance Sheets.

The following is a discussion of the Utility’s use of derivative instruments intended to mitigate commodity-related price risk for its customers.

Electricity Procurement

The Utility obtains electricity from a diverse mix of resources, including third-party power purchase agreements, amounts allocated under DWR contracts, and its own electricity generation facilities. The amount of electricity the Utility needs to meet the demands of customers and that is not satisfied from the Utility’s own generation facilities, existing purchase contracts, or DWR contracts allocated to the Utility’s customers is subject to change for a number of reasons, including:

• 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 or contracted resources to generate power.

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The Utility enters into third-party power purchase agreements to ensure sufficient electricity to meet customer needs. The Utility’s third-party power purchase agreements are generally accounted for as leases, but certain third-party power purchase agreements are considered derivative instruments. The Utility elects to use the normal purchase and sale exception for eligible derivative instruments.

A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms. In order to reduce the volatility in customer rates, the Utility has entered into financial swap contracts to effectively fix the price of future purchases and reduce the cash flow variability associated with fluctuating electricity prices under some of those power purchase agreements. These financial swaps are considered derivative instruments.

Electric Transmission Congestion Revenue Rights

The California Independent System Operator (“CAISO”) controlled electricity transmission grid used by the Utility to transmit power is subject to transmission constraints. As a result, the Utility is subject to financial risk associated with the cost of transmission congestion. The congestion revenue rights (“CRRs”) allow market participants, including load-serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the new day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load-serving entities are allocated CRRs at no cost based on the customer demand or “load” they serve) and an auction phase (in which CRRs are priced at market and available to all market participants). The CRRs held by the Utility are considered derivative instruments.

Natural Gas Procurement (Electric Fuels Portfolio)

The Utility’s electric procurement portfolio is exposed to natural gas price risk primarily through the Utility-owned natural gas generating facilities, tolling agreements, and natural gas-indexed electricity procurement contracts. In order to reduce the volatility in customer rates, the Utility purchases financial instruments such as futures, swaps, and options to reduce future cash flow variability associated with fluctuating natural gas prices. These financial instruments are considered derivative instruments.

Natural Gas Procurement (Core Gas Supply Portfolio)

The Utility enters into physical natural gas commodity contracts to fulfill the needs of its residential and smaller commercial customers known as “core” customers. (The Utility does not procure natural gas for industrial and large commercial, or “non-core,” customers.) Changes in temperature cause natural gas demand to vary daily, monthly, and seasonally. Consequently, varying volumes of gas may be purchased or sold in the multi-month, monthly, and to a lesser extent, daily spot market to balance such seasonal supply and demand. The Utility purchases financial instruments such as swaps and options as part of its core winter hedging program in order to manage customer exposure to high gas prices during peak winter months. These financial instruments are considered derivative instruments.

Volume of Derivative Activity

At December 31, 2010, the volumes of PG&E Corporation’s and the Utility’s outstanding derivative contracts were as follows:

		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)
Natural Gas (3) (MMBtus (4))	Forwards, Futures, and Swaps		427,176,587		308,712,558		—		—
	Options		270,509,308		176,150,000		—		—
Electricity (Megawatt-hours)	Forwards, Futures, and Swaps		5,690,441		6,969,024		3,673,512		4,826,640
	Options		415,450		—		264,096		396,396
	Congestion Revenue Rights		74,313,524		72,070,789		71,997,921		96,986,809

⁽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 2016 and 2022.

⁽³⁾ Amounts shown are for the combined positions of the electric and core gas portfolios.

⁽⁴⁾ Million British Thermal Units.

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Presentation of Derivative Instruments in the Financial Statements

In PG&E Corporation’s and the Utility’s Consolidated Balance Sheets, derivative instruments are presented on a net basis by counterparty where the right of offset exists under a master netting agreement. The net balances include outstanding cash collateral associated with derivative positions.

At December 31, 2010, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

(in millions)	Gross Derivative Balance (1)			Netting (2)			Cash Collateral (2)		Total Derivative Balances
Commodity Risk (PG&E Corporation and the Utility)
Current assets – other	$	56		$	(45	)	$	79	$	90
Other noncurrent assets – other		77			(62	)		96		111
Current liabilities – other		(388	)		45			119		(224	)
Noncurrent liabilities – other		(486	)		62			130		(294	)
Total commodity risk	$	(741	)	$	—		$	424	$	(317	)

⁽¹⁾ See Note 11 of the Notes to the Consolidated Financial Statements 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.

At December 31, 2009, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

(in millions)	Gross Derivative Balance (1)			Netting (2)			Cash Collateral (2)		Total Derivative Balances
Commodity Risk (PG&E Corporation and the Utility)
Current assets – other	$	76		$	(12	)	$	77	$	141
Other noncurrent assets – other		64			(44	)		13		33
Current liabilities – other		(231	)		12			54		(165	)
Noncurrent liabilities – other		(390	)		44			44		(302	)
Total commodity risk	$	(481	)	$	—		$	188	$	(293	)
Other Risk Instruments (3) (PG&E Corporation Only)
Current liabilities – other	$	(13	)	$	—		$	—	$	(13	)
Total derivatives	$	(494	)	$	—		$	188	$	(306	)

⁽¹⁾ See Note 11 of the Notes to the Consolidated Financial Statements 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, which were converted to PG&E Corporation common stock in 2010.

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For the years ended December 31, 2010 and 2009, the gains and losses recorded on PG&E Corporation’s and the Utility’s derivative instruments were as follows:

	Commodity Risk
	(PG&E Corporation and the Utility)
(in millions)	2010			2009
Unrealized gain/(loss) – Regulatory assets and liabilities (1)	$	(260	)	$	15
Realized gain/(loss) – Cost of electricity (2)		(573	)		(701	)
Realized gain/(loss) – Cost of natural gas (2)		(79	)		(54	)
Total commodity risk instruments	$	(912	)	$	(740	)

⁽¹⁾ Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities rather than being recorded to the 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.

Cash inflows and outflows associated with the settlement of all derivative instruments are included in operating cash flows on PG&E Corporation’s and the Utility’s Consolidated Statements of Cash Flows.

The majority of the Utility’s commodity risk-related derivative instruments contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to immediately post additional cash to fully collateralize its net liability derivative positions.

At December 31, 2010, the additional cash collateral that the Utility would be required to post if its credit risk-related contingency features were triggered was as follows:

(in millions)
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized	$  (518)
Related derivatives in an asset position	—
Collateral posting in the normal course of business related to these derivatives	7
Net position of derivative contracts/additional collateral posting requirements (1)	$  (511)

⁽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.

NOTE 11: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value. Fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or a liability. A three-tier fair value hierarchy is established as a basis for considering such assumptions and for inputs used in the valuation methodologies in measuring fair value:

Level 1—Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2—Include other inputs that are directly or indirectly observable in the marketplace.

Level 3—Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

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Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below (money market investments and assets held in rabbi trusts are held by PG&E Corporation and not the Utility):

Fair Value Measurements at December 31, 2010
(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Money market investments	$	138	$	—	$	—	$	138
Nuclear decommissioning trusts
U.S. equity securities (1)		1,029		7		—		1,036
Non-U.S. equity securities		349		—		—		349
U.S. government and agency securities		584		40		—		624
Municipal securities		—		119		—		119
Other fixed income securities		—		66		—		66
Total nuclear decommissioning trusts (2)		1,962		232		—		2,194
Price risk management instruments (Note 10)
Electric (3)		130		—		—		130
Gas (4)		3		—		—		3
Total price risk management instruments		133		—		—		133
Rabbi trusts
Fixed Income securities		—		24		—		24
Life insurance contracts		—		65		—		65
Total rabbi trusts		—		89		—		89
Long-term disability trust
U.S. equity securities (1)		11		24		—		35
Corporate debt securities (1)		—		150		—		150
Total long-term disability trust		11		174		—		185
Total assets	$	2,244	$	495	$	—	$	2,739
Liabilities:
Price risk management instruments (Note 10)
Electric (5)	$	—	$	5	$	403	$	408
Gas (6)		—		1		41		42
Total price risk management instruments		—		6		444		450
Total liabilities	$	—	$	6	$	444	$	450

⁽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 $185 million primarily related to deferred taxes on appreciation of investment value.

⁽³⁾ Balances include the impact of netting adjustments of $359 million to Level 1. Includes natural gas for electric portfolio.

⁽⁴⁾ Balances include the impact of netting adjustments of $44 million to Level 1. Includes natural gas for core customers.

⁽⁵⁾ Balances include the impact of netting adjustments of $66 million to Level 2 and $(48) million to Level 3. Includes natural gas for electric portfolio.

⁽⁶⁾ Balances include the impact of netting adjustments of $3 million to Level 3. Includes natural gas for core customers.

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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 (3)	$	—	$	—	$	12	$	12
Price risk management instruments (Note 10)
Electric (4)		2		73		157		232
Gas (5)		1		—		60		61
Total price risk management instruments		3		73		217		293
Other liabilities		—		—		3		3
Total liabilities	$	3	$	73	$	232	$	308

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⁽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⁾ The dividend participation rights were associated with PG&E Corporation’s Convertible Subordinated Notes which were no longer outstanding as of December 31, 2010.

⁽⁴⁾ 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.

⁽⁵⁾ Balances include the impact of netting adjustments of $13 million to Level 3. Includes natural gas for core customers.

Money Market Investments

PG&E Corporation invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, such as treasury bills, federal agency securities, certificates of deposit, and commercial paper with a maximum weighted average maturity of 60 days or less. PG&E Corporation’s investments in these money market funds are generally valued using unadjusted quotes in an active market for identical assets and are thus classified as Level 1 instruments. Money market funds are recorded as cash and cash equivalents in PG&E Corporation’s Consolidated Balance Sheets.

Trust Assets

The assets held by the nuclear decommissioning trusts, the rabbi trusts related to the non-qualified deferred compensation plans, and the long-term disability trust are comprised primarily of equity securities and debt securities. In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. It is reasonably possible that changes in the market values of investment securities could occur in the near term, and such changes could materially affect the trusts’ fair value.

Equity securities primarily include investments in common stock and commingled funds comprised of equity across multiple industry sectors in the U.S. and other regions of the world. Equity securities are generally valued based on unadjusted prices in active markets for identical transactions and are classified as Level 1.

Debt securities are comprised primarily of fixed income securities that include U.S. government and agency securities, municipal securities, and corporate debt securities. A market based valuation approach is generally used to estimate the fair value of debt securities classified as Level 2 instruments in the tables above. Under a market approach, fair values are determined based on evaluated pricing data, such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.

The Consolidated Balance Sheets of PG&E Corporation and the Utility contain assets held in trust for the PG&E Retirement Plan Master Trust, the Postretirement Life Insurance Trust, and the Postretirement Medical Trusts presented on a net basis. (See Note 12 below.) The pension assets are presented net of pension obligations as noncurrent liabilities – other in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets.

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Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as futures, forwards, swaps, options, and CRRs that are either exchange-traded or over-the-counter traded. (See Note 10 above.)

Futures, forwards, and swaps are valued using observable market prices for the underlying commodity or an identical instrument and are classified as Level 1 or Level 2 instruments. For periods where market data is not available, the Utility extrapolates forward prices. Other futures, forwards, and swaps are considered Level 3 instruments as the determination of their fair value includes the use of unobservable forward prices.

All energy-related options are classified as Level 3 and are valued using a standard option pricing model with various assumptions, including forward prices for the underlying commodity, time value at a risk free rate, and volatility. For periods when market data is not available, the Utility extrapolates these assumptions using internal models.

The Utility holds CRRs to hedge financial risk of CAISO-imposed congestion charges in the day-ahead markets. CRRs are valued based on the forecasted settlement price at the delivery points underlying the CRR using internal models. The Utility also uses the most current annual auction prices published by the CAISO to calibrate internal models. Limited market data is available between auction dates; therefore, CRRs are classified as Level 3 measurements.

The Utility enters into power purchase agreements for the purchase of electricity to meet the demand of its customers. (See Note 10 above.) The Utility uses internal models to determine the fair value of these power purchase agreements. These power purchase agreements include contract terms that extend beyond a period for which an active market exists. The Utility utilizes market data for the underlying commodity to the extent that it is available in determining the fair value. For periods where market data is not available, the Utility extrapolates forward prices. These power purchase agreements are considered Level 3 instruments as the determination of their fair value includes the use of unobservable forward prices.

Transfers between Levels

PG&E Corporation and the Utility recognize any transfers between levels in the fair value hierarchy as of the end of the reporting period. There were no significant transfers between levels for the year ended December 31, 2010.

Level 3 Reconciliation

The following tables present reconciliations for assets and liabilities measured and recorded at fair value on a recurring basis, using significant unobservable inputs (Level 3), for the years ended December 31, 2010 and 2009:

	PG&E Corporation Only						PG&E Corporation and the Utility
(in millions)	Money Market			Dividend Participation Rights			Price Risk Management Instruments			Nuclear Decommissioning 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, 2008	$	12		$	(42	)	$	(156	)	$	5		$	54		$	24		$	(2	)	$	(105	)
Realized and unrealized gains (losses):
Included in earnings		—			2			—			—			12			3			—			17
Included in regulatory assets and liabilities or balancing accounts		—			—			(61	)		1			—			—			(1	)		(61	)
Purchases, issuances, and settlements		(8	)		28			—			—			(43	)		86			—			63
Transfers into Level 3		—			—			—			—			—			—			—			—
Transfers out of Level 3		—			—			—			(6	)		(23	)		(113	)		—			(142	)
Asset (liability) balance as of December 31, 2009	$	4		$	(12	)	$	(217	)	$	—		$	—		$	—		$	(3	)	$	(228	)
Realized and unrealized gains (losses):
Included in earnings		—			—			—			—			—			—			—			—

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Included in regulatory assets and liabilities or balancing accounts		—			—		(227	)		—		—		—		3		(224	)
Purchases, issuances, and settlements		(4	)		12		—			—		—		—		—		8
Transfers into Level 3		—			—		—			—		—		—		—		—
Transfers out of Level 3		—			—		—			—		—		—		—		—
Asset (liability) balance as of December 31, 2010	$	—		$	—	$	(444	)	$	—	$	—	$	—	$	—	$	(444	)

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

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments:

• The fair values of cash, restricted cash and deposits, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2010 and 2009.

• The fair values of the Utility’s fixed rate senior notes and 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 December 31, 2010 and 2009.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

	At December 31,
	2010				2009
(in millions)	Carrying Amount		Fair Value(2)		Carrying Amount		Fair Value(2)
Debt (Note 4):
PG&E Corporation (1)	$	349	$	383	$	597	$	1,096
Utility		10,444		11,314		9,240		9,824
Energy recovery bonds (Note 5)		827		862		1,213		1,269

⁽¹⁾ PG&E Corporation Convertible Subordinated Notes were no longer outstanding as of December 31, 2010.

⁽²⁾ Fair values are determined using readily available quoted market prices.

Nuclear Decommissioning Trust Investments

The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility’s nuclear facilities. At December 31, 2010 and 2009, the Utility had accumulated nuclear decommissioning trust funds with an estimated fair value of $2.0 billion and $1.9 billion, respectively, net of deferred taxes on unrealized gains. In 2010 and 2009, the trusts earned $62 million and $63 million in interest and dividends, respectively. All earnings on the assets held in the trusts, net of authorized disbursements from the trusts and investment management and administrative fees, are reinvested. Amounts may not be released from the decommissioning trusts until authorized by the CPUC.

At December 31, 2010 and 2009, total unrealized losses on the investments held in the trusts were $6 million and $8 million, respectively. The Utility concluded that the unrealized losses were other-than-temporary impairments and recorded a reduction to the nuclear decommissioning trusts assets and the corresponding regulatory liability for asset retirement costs. There were no individually material unrealized losses.

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The following table provides a summary of available-for-sale investments held in the Utility’s nuclear decommissioning trusts:

	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Estimated (1) Fair Value
(in millions)
As of December 31, 2010
Equity securities
U.S.	$	509	$	529	$	(2	)	$	1,036
Non-U.S.		180		170		(1	)		349
Debt securities
U.S. government and agency securities		571		55		(2	)		624
Municipal securities		119		1		(1	)		119
Other fixed income securities		65		1		—			66
Total	$	1,444	$	756	$	(6	)	$	2,194
As of December 31, 2009
Equity securities
U.S.	$	344	$	425	$	(1	)	$	768
Non-U.S.		182		163		(1	)		344
Debt securities
U.S. government and agency securities		656		52		(4	)		704
Municipal securities		89		1		—			90
Other fixed income securities		108		2		(2	)		108
Total	$	1,379	$	643	$	(8	)	$	2,014

⁽¹⁾ Excludes taxes on appreciation of investment value.

The debt securities mature on the following schedule:

As of December 31, 2010	(in millions)
Less than 1 year	$	37
1–5 years		349
5–10 years		215
More than 10 years		208
Total maturities of debt securities	$	809

The following table provides a summary of the activity for the debt and equity securities:

	Year Ended December 31,
	2010			2009			2008
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	1,405		$	1,351		$	1,635
Gross realized gains on sales of securities held as available-for-sale		42			27			30
Gross realized losses on sales of securities held as available-for-sale		(11	)		(55	)		(142	)

NOTE 12: EMPLOYEE BENEFIT PLANS

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees and retirees (referred to collectively as “pension benefits”), contributory postretirement medical plans for eligible employees and retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees (referred to collectively as “other benefits”). PG&E Corporation and the Utility have elected that certain of the trusts underlying these plans be treated under the Code as qualified trusts. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain Code limitations. PG&E Corporation and the Utility use a December 31 measurement date for all plans.

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PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements. Based upon current assumptions and available information, the Utility has not identified any minimum funding requirements related to its pension plans.

Change in Plan Assets, Benefit Obligations, and Funded Status

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2010 and 2009:

Pension Benefits

(in millions)	2010			2009
Change in plan assets:
Fair value of plan assets at January 1	$	9,330		$	8,066
Actual return on plan assets		1,235			1,523
Company contributions		162			187
Benefits and expenses paid		(477	)		(446	)
Fair value of plan assets at December 31	$	10,250		$	9,330
Change in benefit obligation:
Projected benefit obligation at January 1	$	10,766		$	9,767
Service cost for benefits earned		253			227
Interest cost		645			624
Actuarial loss		856			494
Plan amendments		(1	)		71
Transitional costs		4			3
Benefits paid		(452	)		(420	)
Projected benefit obligation at December 31 (1)	$	12,071		$	10,766
Funded status:
Current liability	$	(5	)	$	(5	)
Noncurrent liability		(1,816	)		(1,431	)
Accrued benefit cost at December 31	$	(1,821	)	$	(1,436	)

⁽¹⁾ PG&E Corporation’s accumulated benefit obligation was $10,653 million and $9,527 million at December 31, 2010 and 2009, respectively.

Other Benefits

(in millions)	2010			2009
Change in plan assets:
Fair value of plan assets at January 1	$	1,169		$	990
Actual return on plan assets		147			166
Company contributions		94			87
Plan participant contribution		49			42
Benefits and expenses paid		(122	)		(116	)
Fair value of plan assets at December 31	$	1,337		$	1,169
Change in benefit obligation:
Benefit obligation at January 1	$	1,511		$	1,382
Service cost for benefits earned		36			30
Interest cost		88			87
Actuarial loss		52			72
Plan amendments		128			—
Transitional costs		1			1
Benefits paid		(113	)		(106	)
Federal subsidy on benefits paid		3			4
Plan participant contributions		49			41
Benefit obligation at December 31	$	1,755		$	1,511
Funded status:
Noncurrent liability	$	(418	)	$	(342	)
Accrued benefit cost at December 31	$	(418	)	$	(342	)

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There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

On February 16, 2010, the Utility amended its contributory postretirement medical plans for retirees to provide for additional employer contributions towards retiree premiums. The plan amendment was accounted for as a plan modification that required re-measurement of the accumulated benefit obligation, plan assets, and periodic benefit costs. The inputs and assumptions used in re-measurement did not change significantly from December 31, 2009 and did not have a material impact on the funded status of the plans. The re-measurement of the accumulated benefit obligation and plan assets resulted in an increase to other postretirement benefits and a decrease to other comprehensive income of $148 million. The impact to net periodic benefit cost was not material.

Components of Net Periodic Benefit Cost

Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income for 2010, 2009, and 2008 is as follows:

Pension Benefits

	December 31,
(in millions)	2010			2009			2008
Service cost for benefits earned	$	279		$	259		$	236
Interest cost		645			624			581
Expected return on plan assets		(624	)		(579	)		(696	)
Amortization of prior service cost		53			53			47
Amortization of unrecognized loss		44			101			1
Net periodic benefit cost		397			458			169
Less: transfer to regulatory account (1)		(233	)		(294	)		(4	)
Total	$	164		$	164		$	165

⁽¹⁾ The Utility recorded $233 million, $295 million, and $4 million for the years ended December 31, 2010, 2009, and 2008, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.

Other Benefits

	December 31,
(in millions)	2010			2009			2008
Service cost for benefits earned	$	36		$	30		$	29
Interest cost		88			87			81
Expected return on plan assets		(74	)		(68	)		(93	)
Amortization of transition obligation		26			26			26
Amortization of prior service cost		25			16			16
Amortization of unrecognized loss (gain)		3			3			(15	)
Net periodic benefit cost	$	104		$	94		$	44

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Components of Accumulated Other Comprehensive Income (Loss)

PG&E Corporation and the Utility record the net periodic benefit cost for pension benefits and other benefits as a component of accumulated other comprehensive income (loss), net of tax. Net periodic benefit cost is composed of unrecognized prior service costs, unrecognized gains and losses, and unrecognized net transition obligations as components of accumulated other comprehensive income, net of tax. (See Note 2 above.)

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Regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between pension expense or income for accounting purposes and pension expense or income for ratemaking, which is based on a funding approach. A regulatory adjustment is also recorded for the amounts that would otherwise be charged to accumulated other comprehensive income for the pension benefits related to the Utility’s defined benefit pension plan. The Utility would record a regulatory liability for a portion of the credit balance in accumulated other comprehensive income, should the other benefits be in an overfunded position. However, this recovery mechanism does not allow the Utility to record a regulatory asset for an underfunded position related to other benefits. Therefore, the charge remains in accumulated other comprehensive income (loss) for other benefits.

The estimated amounts that will be amortized into net periodic benefit cost for PG&E Corporation in 2011 are as follows:

Pension Benefits

(in millions)
Unrecognized prior service cost	$	35
Unrecognized net loss		48
Total	$	83

Other Benefits

(in millions)
Unrecognized prior service cost	$	26
Unrecognized net loss		4
Unrecognized net transition obligation		26
Total	$	56

There were no material differences between the estimated amounts that will be amortized into net period benefit costs for PG&E Corporation and the Utility.

Medicare Prescription Drug, Improvement and Modernization Act of 2003

The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 establishes a prescription drug benefit under Medicare (“Medicare Part D”) and a tax-exempt federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that actuarially is at least equivalent to Medicare Part D. PG&E Corporation and the Utility determined that benefits provided to certain participants actuarially will be at least equivalent to Medicare Part D. Therefore, PG&E Corporation and the Utility are entitled to a tax-exempt subsidy that reduced the accumulated postretirement benefit obligation under the defined benefit medical plan at December 31, 2010 and 2009 and reduced the net periodic cost for 2010 and 2009 by the following amounts:

(in millions)	2010		2009
Accumulated postretirement benefit obligation reduction	$	72	$	71
Net periodic benefit cost reduction		1		7

On March 30, 2010, federal healthcare legislation was signed eliminating the deduction for subsidy contributions after 2012. (See Note 9 above.)

There was no material difference between PG&E Corporation’s and the Utility’s Medicare Part D subsidy during 2010.

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Valuation Assumptions

The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic cost. The following weighted average year-end assumptions were used in determining the plans’ projected benefit obligations and net benefit cost.

	Pension Benefits									Other Benefits
	December 31,									December 31,
	2010			2009			2008			2010			2009			2008
Discount rate		5.42	%		5.97	%		6.31	%		5.11–5.56	%		5.66–6.09	%		5.85–6.33	%
Average rate of future compensation increases		5.00	%		5.00	%		5.00	%		—			—			—
Expected return on plan assets		6.60	%		6.80	%		7.30	%		5.20–6.60	%		5.80–6.90	%		7.00–7.30	%

The assumed health care cost trend rate as of December 31, 2010 is 8%, decreasing gradually to an ultimate trend rate in 2018 and beyond of approximately 5%. A one-percentage-point change in assumed health care cost trend rate would have the following effects:

(in millions)	One- Percentage- Point Increase		One- Percentage- Point Decrease
Effect on postretirement benefit obligation	$	83	$	(86	)
Effect on service and interest cost		7		(7	)

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the pension plan, the assumed return of 6.6% compares to a ten-year actual return of 6.2%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 600 Aa-grade non-callable bonds at December 31, 2010. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

The difference between actual and expected return on plan assets is included in unrecognized gain (loss), and is considered in the determination of future net periodic benefit income (cost). The actual return on plan assets for 2009 was lower than the expected return due to the significant decline in equity market values that occurred in 2009. The actual return on plan assets in 2010 was in line with the expectations.

Investment Policies and Strategies

The financial position of PG&E Corporation’s and the Utility’s funded employee benefit plans is driven by the relationship between plan assets and liabilities. As noted above, the funded status is the difference between the fair value of plan assets and projected benefit obligations. Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs for financial reporting as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended (“ERISA”). PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility.

Interest rate risk and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility. In addition to affecting the trust’s fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields. To manage this risk, PG&E Corporation’s and the Utility’s trusts hold significant allocations to fixed income investments that include U.S. government securities, corporate securities, interest rate swaps, and other fixed income securities. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return. The equity investment allocation is implemented through diversified U.S., non-U.S., and global portfolios that include common stock and commingled funds across multiple industry sectors. Absolute return investments include hedge fund portfolios that diversify the plan’s holdings in equity and fixed income investments by exhibiting returns with low correlation to the direction of these markets. Over the last three years, target allocations to equity investments have generally declined in favor of longer-maturity fixed income investments as a means of dampening future funded status volatility.

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PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets. The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation. Trust investment policies and investment manager guidelines include provisions to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments.

The target asset allocation percentages for major categories of trust assets for pension and other benefit plans at December 31, 2011, 2010, and 2009 are as follows:

	Pension Benefits									Other Benefits
	2011			2010			2009			2011			2010			2009
U.S. Equity		26	%		26	%		32	%		28	%		26	%		37	%
Non-U.S. Equity		14	%		14	%		18	%		15	%		13	%		18	%
Global Equity		5	%		5	%		5	%		3	%		3	%		3	%
Absolute Return		5	%		5	%		5	%		4	%		3	%		3	%
Fixed Income		50	%		50	%		40	%		50	%		54	%		34	%
Cash Equivalents		—	%		—	%		—	%		0	%		1	%		5	%
Total		100	%		100	%		100	%		100	%		100	%		100	%

Fair Value Measurements

The following tables present the fair value of plan assets for pension and other benefit plans by major asset category at December 31, 2010 and 2009.

Fair Value Measurements as of December 31, 2010
(in millions)	Level 1		Level 2		Level 3		Total
Pension Benefits:
U.S. Equity	$	328	$	2,482	$	—	$	2,810
Non-U.S. Equity		356		1,111		—		1,467
Global Equity		177		360		—		537
Absolute Return		—		—		494		494
Fixed Income:
U.S. Government		790		233		—		1,023
Corporate		6		2,724		549		3,279
Other		52		393		120		565
Cash Equivalents		20		—		—		20
Total	$	1,729	$	7,303	$	1,163	$	10,195
Other Benefits:
U.S. Equity	$	104	$	230	$	—	$	334
Non-U.S. Equity		118		80		—		198
Global Equity		18		29		—		47
Absolute Return		—		—		47		47
Fixed Income:
U.S. Government		73		14		—		87
Corporate		8		457		129		594
Other		3		21		10		34
Cash Equivalents		13		—		—		13
Total	$	337	$	831	$	186	$	1,354
Other Assets								38
Total Plan Assets at Fair Value							$	11,587

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Fair Value Measurements as of December 31, 2009
(in millions)	Level 1			Level 2		Level 3		Total
Pension Benefits:
U.S. Equity	$	411		$	2,065	$	—	$	2,476
Non-U.S. Equity		316			1,018		—		1,334
Global Equity		162			317		—		479
Absolute Return		—			—		340		340
Fixed Income:
U.S. Government		585			262		—		847
Corporate		25			2,455		531		3,011
Other		(8	)		233		190		415
Cash Equivalents		378			31		—		409
Total	$	1,869		$	6,381	$	1,061	$	9,311
Other Benefits:
U.S. Equity	$	88		$	218	$	—	$	306
Non-U.S. Equity		81			68		—		149
Global Equity		—			8		—		8
Absolute Return		—			—		32		32
Fixed Income:
U.S. Government		40			15		—		55
Corporate		82			275		124		481
Other		(1	)		13		17		29
Cash Equivalents		111			—		—		111
Total	$	401		$	597	$	173	$	1,171
Other Assets									17
Total Plan Assets at Fair Value								$	10,499

Equity Securities

The U.S., Non-U.S., and combined Global Equity categories include equity investments in common stock and commingled funds comprised of equity across multiple industries and regions of the world. Equity investments in common stock are actively traded on a public exchange and are therefore considered Level 1 assets. These equity investments are generally valued based on unadjusted prices in active markets for identical securities. Commingled funds are maintained by investment companies for large institutional investors and are not publicly traded. Commingled funds are comprised primarily of underlying equity securities that are publicly traded on exchanges, and price quotes for the assets held by these funds are readily observable and available. Commingled funds are categorized as Level 2 assets.

Absolute Return

The Absolute Return category includes portfolios of hedge funds that are valued based on a variety of proprietary and non-proprietary valuation methods, including unadjusted prices for publicly-traded securities in active markets. Hedge funds are considered Level 3 assets.

Fixed Income

The Fixed Income category includes U.S. government securities, corporate securities, and other fixed income securities.

U.S. government fixed income primarily consists of U.S. Treasury notes and U.S. government bonds that are valued based on quoted market prices or evaluated pricing data for similar securities adjusted for observable differences. These securities are categorized as Level 1 or Level 2 assets.

Corporate fixed income primarily includes investment grade bonds of U.S. issuers across multiple industries that are valued based on a compilation of primarily observable information or broker quotes in non-active markets. The fair value of corporate bonds is determined using recently executed transactions, market price quotations (where observable), bond spreads or credit default swap spreads obtained from independent external parties such as vendors and brokers adjusted for any basis difference between cash and

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derivative instruments. These securities are classified as Level 2 assets. Corporate fixed income also includes one commingled fund comprised of private corporate debt instruments. The fund is valued using pricing models and valuation inputs that are unobservable and is considered a Level 3 asset.

Other fixed income primarily includes pass-through and asset-backed securities. Pass-through securities are valued based on benchmark yields created using observable market inputs and are Level 2 assets. Asset-backed securities are primarily valued based on broker quotes in non-active markets and are considered Level 3 assets. Other fixed income also includes municipal bonds and futures. Municipal bonds are valued based on a compilation of primarily observable information or broker quotes in non-active markets and are considered Level 2 assets. Futures are valued based on unadjusted prices in active markets and are Level 1 assets.

Cash Equivalents

Cash equivalents consist primarily of money markets and commingled funds of short-term securities that are considered Level 1 assets and valued at the net asset value of $1 per unit. The number of units held by the plan fluctuates based on the unadjusted price changes in active markets for the funds’ underlying assets.

Transfers between Levels

PG&E Corporation and the Utility recognize any transfers between levels in the fair value hierarchy as of the end of the reporting period. There were no significant transfers between levels for the year ended December 31, 2010.

Level 3 Reconciliation

The following table is a reconciliation of changes in the fair value of instruments for pension and other benefit plans that have been classified as Level 3 for the years ended December 31, 2010 and 2009:

(in millions)	Absolute Return		Corporate Fixed Income			Other Fixed Income			Total
Pension Benefits:
Balance as of December 31, 2009	$	340	$	531		$	190		$	1,061
Actual return on plan assets:
Relating to assets still held at the reporting date		44		52			5			101
Relating to assets sold during the period		5		5			5			15
Purchases, sales, and settlements		105		(39	)		(80	)		(14	)
Transfers into (out of) Level 3		—		—			—			—
Balance as of December 31, 2010	$	494	$	549		$	120		$	1,163
Other Benefits:
Balance as of December 31, 2009	$	32	$	124		$	17		$	173
Actual return on plan assets:
Relating to assets still held at the reporting date		4		15			—			19
Relating to assets sold during the period		1		(2	)		—			(1	)
Purchases, sales, and settlements		10		(8	)		(7	)		(5	)
Transfers into (out of) Level 3		—		—			—			—
Balance as of December 31, 2010	$	47	$	129		$	10		$	186

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(in millions)	Absolute Return		Corporate Fixed Income			Other Fixed Income			Total
Pension Benefits:
Balance as of December 31, 2008	$	263	$	457		$	291		$	1,011
Actual return on plan assets:
Relating to assets still held at the reporting date		15		82			14			111
Relating to assets sold during the period		4		4			12			20
Purchases, sales, and settlements		58		(11	)		(127	)		(80	)
Transfers into (out of) Level 3		—		(1	)		—			(1	)
Balance as of December 31, 2009	$	340	$	531		$	190		$	1,061
Other Benefits:
Balance as of December 31, 2008	$	25	$	116		$	25		$	166
Actual return on plan assets:
Relating to assets still held at the reporting date		2		15			1			18
Relating to assets sold during the period		—		1			1			2
Purchases, sales, and settlements		5		(8	)		(10	)		(13	)
Transfers into (out of) Level 3		—		—			—			—
Balance as of December 31, 2009	$	32	$	124		$	17		$	173

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $162 million to the pension benefit plans and $94 million to the other benefit plans in 2010. These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements. None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2010. The Utility’s pension benefits met all the funding requirements under ERISA. PG&E Corporation and the Utility expect to make total contributions of approximately $245 million and $58 million to the pension plan and other postretirement benefit plans, respectively, for 2011.

Benefits Payments

As of December 31, 2010, the estimated benefits expected to be paid in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter for PG&E Corporation, are as follows:

	Pension		Other
(in millions)
2011	$	509	$	114
2012		547		117
2013		586		122
2014		624		128
2015		663		133
2016–2020		3,869		725

There were no material differences between the estimated benefits expected to be paid for PG&E Corporation and the Utility for the years presented above.

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Defined Contribution Benefit Plans

PG&E Corporation sponsors employee retirement savings plans, including a 401(k) defined contribution savings plan. These plans are qualified under applicable sections of the Code and provide for tax-deferred salary deductions, after-tax employee contributions, and employer contributions. Employer contribution expense reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:

(in millions)
Year ended December 31,
2010	$	56
2009		52
2008		53

There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.

NOTE 13: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility’s proceeding under Chapter 11 seeking payment for energy supplied to the Utility’s customers through the wholesale electricity markets operated by the CAISO and the California Power Exchange (“PX”) between May 2000 and June 2001. These claims, which the Utility disputes, are being addressed in various FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and the PX wholesale electricity markets between May 2000 and June 2001. At December 31, 2010 and December 31, 2009, the Utility held $512 million and $515 million in escrow, respectively, including interest earned, for payment of the remaining net disputed claims. These amounts are included within restricted cash on the Consolidated Balance Sheets.

While the FERC and judicial proceedings have been pending, the Utility entered into a number of settlements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. These settlement agreements provide that the amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. The proceeds from these settlements, after deductions for contingencies based on the outcome of the various refund offset and interest issues being considered by the FERC, will continue to be refunded to customers in rates. Additional settlement discussions with other electricity suppliers are ongoing. Any net refunds, claim offsets, or other credits that the Utility receives from energy suppliers through resolution of the remaining disputed claims, either through settlement or the conclusion of the various FERC and judicial proceedings, will also be refunded to customers.

The following table presents the changes in the remaining net disputed claims liability and interest accrued from December 31, 2009 to December 31, 2010:

(in millions)
Balance at December 31, 2009	$	946
Interest accrued		30
Less: supplier settlements		(42	)
Balance at December 31, 2010	$	934

At December 31, 2010, the Utility’s net disputed claims liability was $934 million, consisting of $745 million of remaining disputed claims (classified on the Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds) and interest accrued at the FERC-ordered rate of $683 million (classified on the Consolidated Balance Sheets within interest payable) partially offset by accounts receivable from the CAISO and the PX of $494 million (classified on the Consolidated Balance Sheets within accounts receivable – other).

Interest accrues on the net liability for disputed claims at the FERC-ordered rate, which is higher than the rate earned by the Utility on the escrow balance. Although the Utility has been collecting the difference between the accrued interest and the earned interest from customers, this amount is not held in escrow. If the amount of interest accrued at the FERC-ordered rate is greater than the amount of interest ultimately determined to be owed with respect to disputed claims, the Utility would refund to customers any excess net interest collected from customers. The amount of any interest that the Utility may be required to pay will depend on the final amounts to be paid by the Utility with respect to the disputed claims and when such interest is paid.

PG&E Corporation and the Utility are unable to predict when the FERC or judicial proceedings that are still pending will be resolved, and the amount of any potential refunds that the Utility may receive or the amount of disputed claims, including interest that the Utility will be required to pay.

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NOTE 14: RELATED PARTY AGREEMENTS AND TRANSACTIONS

The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.

The Utility’s significant related party transactions were as follows:

	Year Ended December 31,
	2010		2009		2008
(in millions)
Utility revenues from:
Administrative services provided to PG&E Corporation	$	7	$	5	$	4
Utility expenses from:
Administrative services received from PG&E Corporation	$	55	$	62	$	122
Utility employee benefit due to PG&E Corporation		27		3		2

At December 31, 2010 and December 31, 2009, the Utility had a receivable of $89 million and $26 million, respectively, from PG&E Corporation included in accounts receivable – other and other noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and a payable of $16 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

NOTE 15: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments in connection with agreements entered into to support the Utility’s operating activities. PG&E Corporation and the Utility also have significant contingencies arising from their operations, including contingencies related to guarantees, regulatory proceedings, nuclear operations, environmental compliance and remediation, tax matters, and legal matters.

Commitments

Utility

Third-Party Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either gas or electricity at the date of purchase.

The table below shows the costs incurred for each type of third-party power purchase agreement at December 31, 2010:

	Payments
(in millions)	2010		2009		2008
Qualifying facilities(1) (2)	$	1,164	$	1,210	$	1,724
Renewable energy contracts(1)		573		362		302
Other power purchase agreements(1)		598		643		2,036
Irrigation district and water agencies(1)		59		58		69

⁽¹⁾ The amounts above do not include payments related to DWR purchases for the benefit of the Utility’s customers, as the Utility only acts as an agent for the DWR.

⁽²⁾ Payments include $321, $344, and $412 attributable to renewable energy contracts with qualifying facilities at December 31, 2010, 2009 and 2008, respectively.

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Qualifying Facility Power Purchase Agreements – Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), electric utilities are required to purchase energy and capacity from independent power producers with generation facilities that meet the statutory definition of a qualifying facility (“QF”). QFs include small power production facilities whose primary energy sources are co-generation facilities that produce combined heat and power (“CHP”) and renewable generation facilities. To implement the purchase requirements of PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with QFs and approved the applicable terms and conditions, prices, and eligibility requirements. These agreements require the Utility to pay for energy and capacity. Energy payments are based on the QF’s actual electrical output and CPUC-approved energy prices, while capacity payments are based on the QF’s total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the QF exceeds or fails to meet performance requirements specified in the applicable power purchase agreement.

As of December 31, 2010, the Utility had agreements with 226 QFs for approximately 3,700 megawatts (“MW”) that are in operation. Agreements for approximately 3,400 MW expire at various dates between 2011 and 2028. QF power purchase agreements for approximately 300 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option. The Utility also has power purchase agreements with 75 inoperative QFs. The total of approximately 3,700 MW consists of approximately 2,500 MW from cogeneration projects and approximately 1,200 MW from renewable sources. No single QF accounted for more than 5% of the Utility’s 2010, 2009, or 2008 electricity sources.

Renewable Energy Power Purchase Agreements – The Utility has entered into various contracts to purchase renewable energy to help the Utility meet the current renewable portfolio standard (“RPS”) requirement. In general, renewable contract payments consist primarily of per megawatt hour (“MWh”) payments and either a small or no fixed capacity payment, as opposed to contracts with non-renewable sources, which generally include both a per MWh payment and a fixed capacity payment. As shown in the table below, the Utility’s commitments for energy payments under these renewable energy agreements are expected to grow significantly, assuming that the facilities are developed timely. No single supplier accounted for more than 5% of the Utility’s 2010, 2009, or 2008 electricity sources.

Other Power Purchase Agreements – In accordance with the Utility’s CPUC-approved long-term procurement plans, the Utility has entered into several power purchase agreements with third parties. The Utility’s obligations under a portion of these agreements are contingent on the third party’s development of a new generation facility to provide the power to be purchased by the Utility under the agreements.

Irrigation District and Water Agency Power Purchase Agreements – The Utility has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts’ and water agencies’ debt service requirements, whether or not any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2011 to 2031. Irrigation districts and water agencies consist of small and large hydro plants. No single irrigation district or water agency accounted for more than 5% of the Utility’s 2010, 2009, or 2008 electricity sources.

At December 31, 2010, the undiscounted future expected power purchase agreement payments were as follows:

	Qualifying Facility				Renewable (Other than QF)				Irrigation District & Water Agency				Other				Total Payments
(in millions)	Energy		Capacity		Energy		Capacity		Operations & Maintenance		Debt Service		Energy		Capacity
2011	$	720	$	366	$	796	$	8	$	59	$	21	$	3	$	691	$	2,664
2012		545		321		944		9		45		21		3		684		2,572
2013		542		312		1,261		9		28		15		3		822		2,992
2014		548		301		1,647		—		13		12		1		605		3,127
2015		509		259		1,942		—		11		11		—		583		3,315
Thereafter		3,129		1,263		40,882		5		27		16		—		4,227		49,549
Total	$	5,993	$	2,822	$	47,472	$	31	$	183	$	96	$	10	$	7,612	$	64,219

Some of the power purchase agreements that the Utility entered into with independent power producers that are QFs are treated as capital leases. The following table shows the future fixed capacity payments due under the QF contracts that are treated as capital leases. (These amounts are also included in the table above.) The fixed capacity payments are discounted to their present value in the table below using the Utility’s incremental borrowing rate at the inception of the leases. The amount of this discount is shown in the table below as the amount representing interest.

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(in millions)
2011	$	50
2012		50
2013		50
2014		42
2015		38
Thereafter		124
Total fixed capacity payments		354
Less: amount representing interest		72
Present value of fixed capacity payments	$	282

Minimum lease payments associated with the lease obligation are included in cost of electricity on PG&E Corporation’s and the Utility’s Consolidated Statements of Income. The timing of the recognition of the lease expense conforms to the ratemaking treatment for the Utility’s recovery of the cost of electricity. The QF contracts that are treated as capital leases expire between April 2014 and September 2021.

The present value of the fixed capacity payments due under these contracts is recorded on PG&E Corporation’s and the Utility’s Consolidated Balance Sheets. At December 31, 2010 and December 31, 2009, current liabilities – other included $34 million and $32 million, respectively, and noncurrent liabilities – other included $248 million and $282 million, respectively. The corresponding assets at December 31, 2010 and December 31, 2009 of $282 million and $314 million including accumulated amortization of $126 million and $94 million, respectively are included in property, plant, and equipment on PG&E Corporation’s and the Utility’s Consolidated Balance Sheets.

Natural Gas Supply, Transportation, and Storage Commitments 

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers. The contract lengths and quantities of the Utility’s portfolio of natural gas procurement contracts can fluctuate based on market conditions. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. In addition, the Utility has contracted for gas storage services in northern California in order to better meet core customers’ winter peak loads. At December 31, 2010, the Utility’s undiscounted obligations for natural gas purchases, natural gas transportation services, and natural gas storage were as follows:

(in millions)
2011	$	710
2012		273
2013		191
2014		170
2015		161
Thereafter		1,128
Total (1)	$	2,633

⁽¹⁾ Amounts above include firm transportation contracts for the Ruby Pipeline (a 1.5 billion cubic feet per day (“bcf/d”) pipeline which is currently under construction and expected to become operational in the summer of 2011, and the Utility has contracted for a capacity of approximately 0.4 bcf/d).

Payments for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $1.6 billion in 2010, $1.4 billion in 2009, and $2.7 billion in 2008.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from 1 to 14 years and are intended to ensure long-term fuel supply. The contracts for uranium and for conversion and enrichment services provide for 100% coverage of reactor requirements through 2016, while contracts for fuel fabrication services provide for 100% coverage of reactor requirements through 2017. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices. New agreements are primarily based on forward market pricing. Price increases in the uranium and enrichment service markets are providing upward pressure on nuclear fuel costs starting in 2011.

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At December 31, 2010, the undiscounted obligations under nuclear fuel agreements were as follows:

(in millions)
2011	$	84
2012		69
2013		105
2014		132
2015		191
Thereafter		1,057
Total	$	1,638

Payments for nuclear fuel amounted to $144 million in 2010, $141 million in 2009, and $157 million in 2008.

Other Commitments and Operating Leases

The Utility has other commitments relating to operating leases. At December 31, 2010, the future minimum payments related to other commitments were as follows:

(in millions)
2011	$	25
2012		22
2013		19
2014		14
2015		11
Thereafter		73
Total	$	164

Payments for other commitments and operating leases amounted to $25 million in 2010, $22 million in 2009, and $41 million in 2008. PG&E Corporation and the Utility had operating leases on office facilities expiring at various dates from 2011 to 2020. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 1% to 4%. The rentals payable under these leases may increase by a fixed amount each year, a percentage of a base year, or the consumer price index. Most leases contain extension options ranging between one and five years.

Underground Electric Facilities

At December 31, 2010, the Utility was committed to spending approximately $236 million for the conversion of existing overhead electric facilities to underground electric facilities. These funds are conditionally committed depending on the timing of the work, including the schedules of the respective cities, counties, and communications utilities involved. The Utility expects to spend approximately $42 million to $60 million each year in connection with these projects. Consistent with past practice, the Utility expects that these capital expenditures will be included in rate base as each individual project is completed and recoverable in rates charged to customers.

Contingencies

PG&E Corporation

PG&E Corporation retains a guarantee related to certain obligations of its former subsidiary, NEGT, that were issued to the purchaser of an NEGT subsidiary company in 2000. PG&E Corporation’s primary remaining exposure relates to any potential environmental obligations that were known to NEGT at the time of the sale but not disclosed to the purchaser, and is limited to $150 million. PG&E Corporation has not received any claims nor does it consider it probable that any claims will be made under the guarantee. PG&E Corporation believes that its potential exposure under this guarantee would not have a material impact on its financial condition or results of operations.

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Utility

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 through 2008 energy efficiency programs. On December 16, 2010, the CPUC awarded the Utility a final true-up payment award of $29.1 million for the 2006 through 2008 energy efficiency program cycle. Including this award, the Utility has earned incentive revenues totaling $104 million through December 31, 2010 based on the energy savings achieved through implementation of the Utility’s energy efficiency programs during the 2006 through 2008 program cycle. The CPUC has directed the utilities to file their applications for incentive awards for 2009 energy efficiency program performance by June 30, 2011 to enable the CPUC to issue a final decision by the end of 2011.

On November 15, 2010, a proposed decision was issued that if, adopted by the CPUC, would modify the incentive mechanism that would apply to the 2010 through 2012 program cycle. Among other changes, the proposed modification would limit the total amount of the incentive award or penalty that could be awarded to, or imposed on, all the investor-owned utilities to $189 million. If the proposed decision is adopted, the Utility’s opportunity to earn incentive revenues would be limited compared to the mechanism that was in place for the 2006-2008 program cycle.

Spent Nuclear Fuel Storage Proceedings

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 Power Plant (“Diablo Canyon”) and its retired nuclear facility at Humboldt Bay.

Because the DOE failed to develop a permanent storage site, the Utility obtained a permit from the NRC to build an on-site dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024. The construction of the dry cask storage facility is complete. During 2009, the Utility moved all the spent nuclear fuel that was scheduled to be moved into dry cask storage. An appeal of the NRC’s issuance of the permit is still pending in the U.S. Court of Appeals for the Ninth Circuit. The appellants claim that the NRC failed to adequately consider environmental impacts of a potential terrorist attack at Diablo Canyon. The Ninth Circuit heard oral arguments on November 4, 2010. The Utility expects a decision from the Ninth Circuit in 2011.

As a result of the DOE’s failure to build a 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 sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, on March 30, 2010, the U.S. Court of Federal Claims awarded the Utility $89 million. The DOE filed an appeal of this decision on May 28, 2010. On August 3, 2010, the Utility filed two complaints against the DOE in the U.S. Court of Federal Claims seeking to recover all costs incurred since 2005 to build on-site storage facilities. The Utility estimates that it has incurred costs of at least $205 million since 2005. Amounts recovered from the DOE will be credited to customers.

Nuclear Insurance

The Utility has several types of nuclear insurance for the two nuclear operating units at Diablo Canyon and for its retired nuclear generation facility at Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited (“NEIL”). NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.2 billion per incident for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $42 million per one-year policy term.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of terrorism cause damages covered under any of the nuclear insurance policies issued by NEIL to any NEIL member, the maximum recovery under all those nuclear insurance policies may not exceed NEIL’s policy limit of $3.2 billion within a 12-month period plus any additional amounts recovered by NEIL for these losses from reinsurance. Certain acts of terrorism may be “certified” by the Secretary of the Treasury. For damages caused by certified acts of terrorism, NEIL can obtain compensation from the federal government and will provide up to its full policy limit of $3.2 billion for each insured loss caused by these certified acts of terrorism. The $3.2 billion amount would not be shared as is described above for damages caused by acts of terrorism that have not been certified.

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Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to $12.6 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The balance of the $12.6 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $235 million per nuclear incident under this program, with payments in each year limited to a maximum of $35 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before October 29, 2013.

The Price-Anderson Act does not apply to public liability claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. Such claims are covered by nuclear liability policies purchased by the enricher and the fuel fabricator as well as by separate supplier’s and transporter’s (“S&T”) insurance policies. The Utility has an S&T policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident. The Utility could incur losses that are either not covered by insurance or exceed the amount of insurance available.

In addition, the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents, covering liabilities in excess of the $53 million of liability insurance.

Legal Matters

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. In addition, the Utility can incur penalties for failure to comply with federal, state, or local lawsuits and regulations.

PG&E Corporation and the Utility record a provision for a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated costs and record a liability based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. These accruals, and the estimates of any additional reasonably possible losses, are reviewed quarterly and are adjusted to reflect the impacts of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. In assessing such contingencies, PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs.

The accrued liability for legal matters (other than third-party liability claims related to the San Bruno accident as discussed below) totaled $55 million at December 31, 2010 and $57 million at December 31, 2009 and is included in PG&E Corporation’s and the Utility’s current liabilities—other in the Consolidated Balance Sheets. Except as discussed below, PG&E Corporation and the Utility do not believe that losses associated with legal matters would have a material adverse impact on their financial condition, results of operations, or cash flows after consideration of the accrued liability at December 31, 2010.

Explosions and Fires in San Bruno, California

On September 9, 2010, an underground 30-inch natural gas transmission pipeline (line 132) owned and operated by the Utility ruptured in a residential area located in the City of San Bruno, California (“San Bruno accident”). The ensuing explosion and fire resulted in the deaths of eight people, injuries to numerous individuals, and extensive property damage. Both the NTSB and the CPUC have begun investigations of the San Bruno accident but they have not yet determined the cause of the pipeline rupture. The NTSB has issued several public statements regarding the investigation and a metallurgy report, all of which are available on the NTSB’s website. The NTSB will hold fact-finding hearings in Washington, D.C. on March 1, 2011 through March 3, 2011 and has stated that it intends to release a total of six factual reports about the San Bruno accident before the hearings begin based on the following topics: metallurgy, operations, human performance, survival factors, fire scene, and meteorology. It is expected that these reports will be made publicly available on the NTSB’s website as each report is released.

As part of the CPUC’s investigation, the CPUC’s staff will examine the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory. The CPUC staff reviewed information about the Utility’s planned and unplanned pressurization events where the pressure has risen above the maximum available operating pressure (“MAOP”) in several of the Utility’s gas transmission lines. On February 2, 2011, the CPUC ordered the Utility to reduce operating pressure twenty percent below the MAOP on certain of its gas transmission pipelines, and also ordered the Utility to reduce operating pressure on other transmission lines that meet certain criteria. The Utility has complied with the CPUC’s order and also has reported to the CPUC that the Utility has identified a number of instances where it had either exceeded MAOP by more than ten percent or had raised the pressure to maintain operational flexibility, including several instances in which the highest pressure reading exceeded MAOP by a few pounds, but not more than ten percent. The CPUC also has appointed an independent review panel to gather and review facts, make a technical assessment of the San Bruno accident and its root cause, and make recommendations for action by the CPUC to ensure such an accident is not repeated. The report of the independent review panel is expected in the second quarter of 2011.

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Several parties have requested that the CPUC institute a formal CPUC investigation into the San Bruno accident. The Utility has filed a response stating that it welcomes the CPUC’s investigation. The CPUC may consider this request at its meeting to be held on February 24, 2011. If the CPUC institutes a formal investigation, the CPUC may impose penalties if it determines that the Utility violated any laws, rules, regulations or orders pertaining to the operations and maintenance of its natural gas system. The CPUC is authorized to assess penalties of up to $20,000, per day, per violation. PG&E Corporation and the Utility anticipate that the CPUC will institute one or more formal investigations regarding these matters. PG&E Corporation and the Utility are unable to estimate a potential loss or range of loss associated with penalties that may be imposed by the CPUC in connection with the San Bruno accident.

In addition to these investigations, as of February 8, 2011, 59 lawsuits on behalf of approximately 177 plaintiffs, including two class action lawsuits, have been filed against PG&E Corporation and the Utility in San Mateo County Superior Courts. In addition, five lawsuits on behalf of 11 plaintiffs have been filed by residents of San Bruno in the San Francisco County Superior Court against PG&E Corporation and the Utility. These lawsuits seek compensation for personal injury and property damage and seek other relief. The class action lawsuits allege causes of action for strict liability, negligence, public nuisance, private nuisance, and declaratory relief. Several other residents also have submitted damage claims to the Utility. The Utility has filed a petition on behalf of PG&E Corporation and the Utility to coordinate these lawsuits in San Mateo County Superior Court. In its statement in support of coordination, the Utility has stated that it is prepared to enter into early mediation in an effort to resolve claims with those plaintiffs willing to do so. A hearing is scheduled for February 24, 2011.

The Utility recorded a provision of $220 million in 2010 for estimated third-party claims related to the San Bruno accident, including personal injury and property damage claims, damage to infrastructure, and other damage claims. The Utility currently estimates that it may incur as much as $400 million for third-party claims. This estimate may change depending on the final determination of the causes for the pipeline rupture and responsibility for the personal injuries and property damages and the number and nature of third-party claims. As more information becomes known, including information resulting from the NTSB and CPUC investigations, management’s estimates and assumptions regarding the amount of third-party liability incurred in connection with the San Bruno accident may change. It is possible that a change in estimate could have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

The Utility maintains liability insurance for damages in the approximate amount of $992 million in excess of a $10 million deductible. Although PG&E Corporation and the Utility currently consider it likely that most of the costs the Utility incurs for third-party claims relating to the San Bruno accident will ultimately be recovered through this insurance, no amounts for insurance recoveries have been recorded as of December 31, 2010. PG&E Corporation and the Utility are unable to predict the amount and timing of insurance recoveries.

CPUC Investigation of the December 24, 2008 Natural Gas Explosion in Rancho Cordova, California

On November 19, 2010, the CPUC began an investigation of the natural gas explosion and fire that occurred on December 24, 2008 in a house in Rancho Cordova, California (“Rancho Cordova accident”). The explosion resulted in one death, injuries to several people, and property damage. The CPUC’s Consumer Protection and Safety Division (“CPSD”) and the NTSB investigated the accident. The NTSB issued its investigative report in May 2010 and the CPSD submitted its report to the CPUC in November 2010. The NTSB determined that the probable cause of the release, ignition, and explosion of natural gas was use of a section of unmarked and out-of-specification polyethylene pipe with inadequate wall thickness that allowed gas to leak from the mechanical coupling that had been installed on September 21, 2006. The NTSB stated that the delayed response by the Utility’s employees was a contributing factor. Based on the CPSD’s and the NTSB’s investigative findings, the CPSD requested the CPUC to open a formal investigation and recommended that the CPUC impose unspecified fines and penalties on the Utility.

In its order instituting the investigation, the CPUC stated that it will determine whether the Utility violated any law, regulation, CPUC general orders or decisions, or other rules or requirement applicable to the Utility’s natural gas service and facilities, and/or engaged in unreasonable and/or imprudent practices in connection with the Rancho Cordova accident. The CPUC also stated that it intends to ascertain whether any management policies and practices contributed to violations of law and the Rancho Cordova accident.

The CPUC ordered the Utility to provide extensive information, from as far back as January 1, 2000, about its practices and procedures at issue. The Utility’s report, due on February 17, 2011, agrees with the NTSB’s conclusions about the probable cause of the accident and explains what process improvements the Utility has made to prevent a similar accident in the future. The CPUC has scheduled a pre-hearing conference for March 1, 2011 to establish a schedule for the proceeding, including the date of an evidentiary hearing. PG&E Corporation and the Utility believe that the CPUC is likely to impose penalties on the Utility in connection with the Rancho Cordova accident.

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PG&E Corporation and the Utility are unable to predict the ultimate outcome of the investigations of the San Bruno and Rancho Cordova accidents. The CPUC is authorized to impose penalties of up to $20,000 per day, per violation. If the CPUC imposed a material amount of penalties on the Utility, there would be a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Environmental Matters

The Utility has been, and may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under federal and state environmental laws. These sites include former manufactured gas plant (“MGP”) sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site.

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. The Utility records an environmental remediation liability when site assessments indicate that remediation is probable and it can reasonably estimate the loss within a range of possible amounts.

The Utility records an environmental remediation liability based on the lower end of the range of estimated costs, unless an amount within the range is a better estimate than any other amount. Amounts recorded are not discounted to their present value.

The Utility had an undiscounted and gross environmental remediation liability of $612 million at December 31, 2010 and $586 million at December 31, 2009. The following table presents the changes in the environmental remediation liability from December 31, 2009:

(in millions)
Balance at December 31, 2009	$	586
Additional remediation costs accrued:
Transfer to regulatory account for recovery		112
Amounts not recoverable from customers		29
Less: Payments		(115	)
Balance at December 31, 2010	$	612

The $612 million accrued at December 31, 2010 consists of the following:

• $45 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California;

• $171 for remediation at the Utility’s natural gas compressor site located on the California border, near Topock, Arizona;

• $85 million related to remediation at divested generation facilities;

• $110 million related to remediation costs for the Utility’s generation and other facilities and for third-party disposal sites;

• $139 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 MGP sites); and

• $62 million related to remediation costs for fossil decommissioning sites.

The Utility has a program, in cooperation with the California Environmental Protection Agency, to evaluate and take appropriate action to mitigate any potential environmental concerns posed by certain former MGPs located throughout the Utility’s service territory. Of the forty one MGP sites owned or operated by the Utility, forty have been or are in the process of being investigated and/or remediated, and the Utility is developing a strategy to investigate and remediate the last site.

Of the $612 million environmental remediation liability, the Utility expects to recover $316 million through the CPUC-approved ratemaking mechanism that authorizes the Utility to recover 90% of hazardous waste remediation costs without a reasonableness review (excluding any remediation associated with the Hinkley natural gas compressor site) and $131 million through the ratemaking mechanism that authorizes the Utility to recover 100% of remediation costs for decommissioning fossil-fueled sites and certain of the Utility’s transmission stations (excluding any remediation associated with divested generation facilities). The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers.

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Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. The Utility’s undiscounted future costs could increase to as much as $1.2 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements.

QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)

	Quarter ended
	December 31		September 30		June 30		March 31
(in millions, except per share amounts)
2010
PG&E CORPORATION
Operating revenues	$	3,621	$	3,513	$	3,232	$	3,475
Operating income		492		503		695		618
Net income		254		261		337		261
Income available for common shareholders		250		258		333		258
Net earnings per common share, basic		0.63		0.66		0.88		0.69
Net earnings per common share, diluted		0.63		0.66		0.86		0.67
Common stock price per share:
High		48.63		48.34		45.00		45.63
Low		45.38		40.52		34.95		40.58
UTILITY
Operating revenues	$	3,620	$	3,513	$	3,232	$	3,475
Operating income		494		505		696		619
Net income		253		265		339		264
Income available for common stock		249		262		335		261
2009
PG&E CORPORATION
Operating revenues	$	3,539	$	3,235	$	3,194	$	3,431
Operating income		523		607		656		513
Net income		277		321		392		244
Income available for common shareholders		273		318		388		241
Net earnings per common share, basic		0.72		0.84		1.03		0.65
Net earnings per common share, diluted		0.71		0.83		1.02		0.65
Common stock price per share:
High		45.79		41.97		39.11		41.06
Low		39.74		36.59		34.60		34.50
UTILITY
Operating revenues	$	3,539	$	3,235	$	3,194	$	3,431
Operating income		525		607		657		513
Net income		267		353		391		239
Income available for common stock		263		350		387		236

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

Management assessed the effectiveness of internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment and those criteria, management has concluded that PG&E Corporation and the Utility maintained effective internal control over financial reporting as of December 31, 2010.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited the Consolidated Balance Sheets of PG&E Corporation and the Utility, as of December 31, 2010 and 2009; and PG&E Corporation’s related consolidated statements of income, equity, and cash flows and the Utility’s related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010. As stated in their report, which is included in this annual report, Deloitte & Touche LLP also has audited PG&E Corporation’s and the Utility’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PG&E Corporation and Pacific Gas and Electric Company

San Francisco, California

We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries (the “Company”) and of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2010 and 2009, and the Company’s related consolidated statements of income, equity, and cash flows and the Utility’s related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010. We also have audited the Company’s and the Utility’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s and the Utility’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s and the Utility’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audits of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of PG&E Corporation and subsidiaries and of Pacific Gas and Electric Company and subsidiaries as of December 31, 2010 and 2009, and the respective results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company and the Utility maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

DELOITTE & TOUCHE LLP

February 17, 2011

San Francisco, California

EX-21

Exhibit 21

Significant Subsidiaries

Parent of Significant Subsidiary	Name of Significant Subsidiary	Jurisdiction of Formation of Subsidiary	Names under which Significant Subsidiary does business
PG&E Corporation	Pacific Gas and Electric Company	CA	Pacific Gas and Electric Company PG&E
Pacific Gas and Electric Company	None

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statements No. 333-149360 on Form S-3, 333-144498 on Form S-3D, and 333-16253, 333-117930, 333-77149, 333-73054, and 333-129422 on Form S-8 of PG&E Corporation and Registration Statements No. 33-62488 and 333-149361 on Form S-3 of Pacific Gas and Electric Company of our reports dated February 17, 2011, relating to the consolidated financial statements and consolidated financial statement schedules of PG&E Corporation and subsidiaries (the “Company”) and Pacific Gas and Electric Company and subsidiaries (the “Utility”) and the effectiveness of the Company’s and the Utility’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of PG&E Corporation and Pacific Gas and Electric Company for the year ended December 31, 2010.

DELOITTE & TOUCHE LLP

February 17, 2011

San Francisco, California

EX-24.1

Exhibit 24.1

RESOLUTION OF THE

BOARD OF DIRECTORS OF

PG&E CORPORATION

February 16, 2011

WHEREAS, the Audit Committee of this Board of Directors has reviewed the audited consolidated financial statements for this corporation for the year ended December 31, 2010, and has recommended to the Board that such financial statements be included in the corporation’s Annual Report on Form 10-K for the year ended December 31, 2010, to be filed with the Securities and Exchange Commission; and

WHEREAS, the Board has authorized said financial statements to be included in said Annual Report on Form 10-K;

NOW, THEREFORE, BE IT RESOLVED that each of HYUN PARK, LINDA Y.H. CHENG, EILEEN O. CHAN, WONDY S. LEE, ERIC A. MONTIZAMBERT, KATHLEEN HAYES, and DOREEN A. LUDEMANN is hereby authorized to sign on behalf of this corporation and as attorneys-in-fact for the Chairman, Chief Executive Officer, and President, the Senior Vice President and Chief Financial Officer, and the Vice President and Controller of this corporation the Annual Report on Form 10-K for the year ended December 31, 2010, required by Section 13 or 15(d) of the Securities Exchange Act of 1934, and all amendments and other filings or documents related thereto to be filed with the Securities and Exchange Commission, and to do any and all acts necessary to satisfy the requirements of the Securities Exchange Act of 1934 and the regulations of the Securities and Exchange Commission adopted thereunder with regard to said Annual Report on Form 10-K.

I, LINDA Y.H. CHENG, do hereby certify that I am Vice President, Corporate Governance and Corporate Secretary of PG&E CORPORATION, a corporation organized and existing under the laws of the State of California; that the above and foregoing is a full, true, and correct copy of a resolution which was duly adopted by the Board of Directors of said corporation at a meeting of said Board which was duly and regularly called and held on February 16, 2011; and that this resolution has never been amended, revoked, or repealed, but is still in full force and effect.

WITNESS my hand and the seal of said corporation hereunto affixed this 16th day of February, 2011.

LINDA Y.H.CHENG

Linda Y.H. Cheng

Vice President, Corporate Governance and

Corporate Secretary

PG&E CORPORATION

C O R P O R A T E

S E A L

RESOLUTION OF THE

BOARD OF DIRECTORS OF

PACIFIC GAS AND ELECTRIC COMPANY

February 16, 2011

WHEREAS, the Audit Committee of this Board of Directors has reviewed the audited consolidated financial statements for this company for the year ended December 31, 2010, and has recommended to the Board that such financial statements be included in the company’s Annual Report on Form 10-K for the year ended December 31, 2010, to be filed with the Securities and Exchange Commission; and

WHEREAS, the Board has authorized said financial statements to be included in said Annual Report on Form 10-K;

NOW, THEREFORE, BE IT RESOLVED that each of HYUN PARK, LINDA Y.H. CHENG, EILEEN O. CHAN, WONDY S. LEE, ERIC A. MONTIZAMBERT, KATHLEEN HAYES, and DOREEN A. LUDEMANN is hereby authorized to sign on behalf of this company and as attorneys-in-fact for the President, the Vice President, Finance and Chief Financial Officer, and the Vice President and Controller of this company the Annual Report on Form 10-K for the year ended December 31, 2010, required by Section 13 or 15(d) of the Securities Exchange Act of 1934, and all amendments and other filings or documents related thereto to be filed with the Securities and Exchange Commission, and to do any and all acts necessary to satisfy the requirements of the Securities Exchange Act of 1934 and the regulations of the Securities and Exchange Commission adopted thereunder with regard to said Annual Report on Form 10-K.

I, LINDA Y.H. CHENG, do hereby certify that I am Vice President, Corporate Governance and Corporate Secretary of PACIFIC GAS AND ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of California; that the above and foregoing is a full, true, and correct copy of a resolution which was duly adopted by the Board of Directors of said corporation at a meeting of said Board which was duly and regularly called and held on February 16, 2011; and that this resolution has never been amended, revoked, or repealed, but is still in full force and effect.

WITNESS my hand and the seal of said corporation hereunto affixed this 16th day of February, 2011.

LINDA Y.H.CHENG

Linda Y.H. Cheng

Vice President, Corporate Governance and

Corporate Secretary

PACIFIC GAS AND ELECTRIC COMPANY

C O R P O R A T E

S E A L

EX-24.2

Exhibit 24.2

POWER OF ATTORNEY

Each of the undersigned Directors of PG&E Corporation hereby constitutes and appoints HYUN PARK, LINDA Y.H. CHENG, EILEEN O. CHAN, WONDY S. LEE, ERIC MONTIZAMBERT, KATHLEEN HAYES, and DOREEN A. LUDEMANN, and each of them, as his or her attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his or her capacity as such Director of said corporation the Annual Report on Form 10-K for the year ended December 31, 2010 required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, we have signed these presents this 16th day of February, 2011.

DAVID R. ANDREWS David R. Andrews	RICHARD A. MESERVE Richard A. Meserve
LEWIS CHEW Lewis Chew	FORREST E. MILLER Forrest E. Miller
C. LEE COX C. Lee Cox	ROSENDO G. PARRA Rosendo G. Parra
PETER A. DARBEE Peter A. Darbee	BARBARA L. RAMBO Barbara L. Rambo
MARYELLEN C. HERRINGER Maryellen C. Herringer	BARRY LAWSON WILLIAMS Barry Lawson Williams
ROGER H. KIMMEL Roger H. Kimmel

POWER OF ATTORNEY

PETER A. DARBEE, the undersigned, Chairman of the Board, Chief Executive Officer, and President of PG&E Corporation, hereby constitutes and appoints HYUN PARK, LINDA Y.H. CHENG, EILEEN O. CHAN, WONDY S. LEE, ERIC MONTIZAMBERT, KATHLEEN HAYES, and DOREEN A. LUDEMANN, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Chairman of the Board, Chief Executive Officer, and President (principal executive officer) of said corporation the Annual Report on Form 10-K for the year ended December 31, 2010 required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, I have signed these presents this 16th day of February, 2011.

PETER A. DARBEE

Peter A. Darbee

POWER OF ATTORNEY

KENT M. HARVEY, the undersigned, Senior Vice President and Chief Financial Officer of PG&E Corporation, hereby constitutes and appoints HYUN PARK, LINDA Y.H. CHENG, EILEEN O. CHAN, WONDY S. LEE, ERIC MONTIZAMBERT, KATHLEEN HAYES, and DOREEN A. LUDEMANN, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Senior Vice President and Chief Financial Officer (principal financial officer) of said corporation the Annual Report on Form 10-K for the year ended December 31, 2010 required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, I have signed these presents this 16th day of February, 2011.

KENT M. HARVEY

Kent M. Harvey

POWER OF ATTORNEY

DINYAR B. MISTRY, the undersigned, Vice President and Controller of PG&E Corporation, hereby constitutes and appoints HYUN PARK, LINDA Y.H. CHENG, EILEEN O. CHAN, WONDY S. LEE, ERIC MONTIZAMBERT, KATHLEEN HAYES, and DOREEN A. LUDEMANN, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Vice President and Controller (principal accounting officer) of said corporation the Annual Report on Form 10-K for the year ended December 31, 2010 required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, I have signed these presents this 16th day of February, 2011.

DINYAR B. MISTRY

Dinyar B. Mistry

POWER OF ATTORNEY

Each of the undersigned Directors of Pacific Gas and Electric Company hereby constitutes and appoints HYUN PARK, LINDA Y.H. CHENG, EILEEN O. CHAN, WONDY S. LEE, ERIC MONTIZAMBERT, KATHLEEN HAYES, and DOREEN A. LUDEMANN, and each of them, as his or her attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his or her capacity as such Director of said corporation the Annual Report on Form 10-K for the year ended December 31, 2010 required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, we have signed these presents this 16th day of February, 2011.

DAVID R. ANDREWS David R. Andrews	ROGER H. KIMMEL Roger H. Kimmel
LEWIS CHEW Lewis Chew	RICHARD A. MESERVE Richard A. Meserve
C. LEE COX C. Lee Cox	FORREST E. MILLER Forrest E. Miller
PETER A. DARBEE Peter A. Darbee	ROSENDO G. PARRA Rosendo G. Parra
MARYELLEN C. HERRINGER Maryellen C. Herringer	BARBARA L. RAMBO Barbara L. Rambo
CHRISTOPHER P. JOHNS Christopher P. Johns	BARRY LAWSON WILLIAMS Barry Lawson Williams

POWER OF ATTORNEY

CHRISTOPHER P. JOHNS, the undersigned, President of Pacific Gas and Electric Company, hereby constitutes and appoints HYUN PARK, LINDA Y.H. CHENG, EILEEN O. CHAN, WONDY S. LEE, ERIC MONTIZAMBERT, KATHLEEN HAYES, and DOREEN A. LUDEMANN, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as President (principal executive officer) of said corporation the Annual Report on Form 10-K for the year ended December 31, 2010 required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, I have signed these presents this 16th day of February, 2011.

CHRISTOPHER P. JOHNS

Christopher P. Johns

POWER OF ATTORNEY

SARA A. CHERRY, the undersigned, Vice President, Finance and Chief Financial Officer of Pacific Gas and Electric Company, hereby constitutes and appoints HYUN PARK, LINDA Y.H. CHENG, EILEEN O. CHAN, WONDY S. LEE, ERIC MONTIZAMBERT, KATHLEEN HAYES, and DOREEN A. LUDEMANN, and each of them, as her attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in her capacity as Vice President, Finance and Chief Financial Officer (principal financial officer) of said corporation the Annual Report on Form 10-K for the year ended December 31, 2010 required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, I have signed these presents this 16th day of February, 2011.

SARA A. CHERRY

Sara A. Cherry

POWER OF ATTORNEY

DINYAR B. MISTRY, the undersigned, Vice President and Controller of Pacific Gas and Electric Company, hereby constitutes and appoints HYUN PARK, LINDA Y.H. CHENG, EILEEN O. CHAN, WONDY S. LEE, ERIC MONTIZAMBERT, KATHLEEN HAYES, and DOREEN A. LUDEMANN, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Vice President and Controller (principal accounting officer) of said corporation the Annual Report on Form 10-K for the year ended December 31, 2010 required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, I have signed these presents this 16th day of February, 2011.

DINYAR B. MISTRY

Dinyar B. Mistry

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Peter A. Darbee, certify that:

1. I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2010 of PG&E Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 17, 2011	PETER A. DARBEE
	Peter A. Darbee
	Chairman, Chief Executive Officer, and President

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Kent M. Harvey, certify that:

1. I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2010 of PG&E Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 17, 2011	KENT M. HARVEY
	Kent M. Harvey
	Senior Vice President and Chief Financial Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Christopher P. Johns, certify that:

1. I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2010 of Pacific Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 17, 2011	CHRISTOPHER P. JOHNS
	Christopher P. Johns
	President

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Sara A. Cherry, certify that:

1. I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2010 of Pacific Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 17, 2011	SARA A. CHERRY
	Sara A. Cherry
	Vice President, Finance and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of PG&E Corporation for the year ended December 31, 2010 (“Form 10-K”), I, Peter A. Darbee, Chairman, Chief Executive Officer, and President of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-K fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of PG&E Corporation.

PETER A. DARBEE

PETER A. DARBEE

Chairman, Chief Executive Officer, and President

February 17, 2011

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of PG&E Corporation for the year ended December 31, 2010 (“Form 10-K”), I, Kent M. Harvey, Senior Vice President and Chief Financial Officer of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-K fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of PG&E Corporation.

KENT M. HARVEY

KENT M. HARVEY

Senior Vice President and

Chief Financial Officer

February 17, 2011

EX-32.2

Exhibit 32.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of Pacific Gas and Electric Company for the year ended December 31, 2010 (“Form 10-K”), I, Christopher P. Johns, President of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-K fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

CHRISTOPHER P. JOHNS

CHRISTOPHER P. JOHNS

President

February 17, 2011

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of Pacific Gas and Electric Company for the year ended December 31, 2010 (“Form 10-K”), I, Sara A. Cherry, Vice President, Finance and Chief Financial Officer of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-K fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

SARA A. CHERRY

SARA A. CHERRY

Vice President, Finance and Chief Financial Officer

February 17, 2011