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, 2012
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

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) 77 Beale Street, P.O. Box 770000 San Francisco, California 94177 (Address of principal executive offices) (Zip 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 þ No 
Pacific Gas and Electric Company	Yes þ 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 þ
Pacific Gas and Electric Company	Yes  No þ

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 þ No 
Pacific Gas and Electric Company	Yes þ 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 þ     No o
Pacific Gas and Electric Company	Yes þ     No o

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	þ
Pacific Gas and Electric Company	þ

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 þ	Large accelerated filer  
Accelerated filer 	Accelerated filer 
Non-accelerated filer 	Non-accelerated filer þ
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 þ
Pacific Gas and Electric Company	Yes  No þ

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2012, the last business day of the most recently completed second fiscal quarter:

PG&E Corporation common stock	$19,276 million
Pacific Gas and Electric Company common stock	Wholly owned by PG&E Corporation

Common Stock outstanding as of February 11, 2013:

PG&E Corporation:	431,436,673
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 2012 Annual Report to Shareholders Part I (Items 1, 1A and 3), Part II (Items 5, 6, 7, 7A, 8 and 9A)

Designated portions of the Joint Proxy Statement relating to the 2013 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14)

TABLE OF CONTENTS

		Page
	Units of Measurement	ii
PART I
Item 1.	Business	1
	General	1
	Regulatory Environment	2
	Ratemaking Mechanisms	7
	Electric Utility Operations	11
	Natural Gas Utility Operations	17
	Public Purpose and Customer Programs	20
	Environmental Matters	22
Item 1A.	Risk Factors	28
Item 1B.	Unresolved Staff Comments	28
Item 2.	Properties	28
Item 3.	Legal Proceedings	28
Item 4.	Mine Safety Disclosures	31
Executive Officers of the Registrants		32
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6.	Selected Financial Data	35
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	35
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 8.	Financial Statements and Supplementary Data	36
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	36
Item 9A.	Controls and Procedures	36
Item 9B.	Other Information	36
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	37
Item 11.	Executive Compensation	37
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	37
Item 13.	Certain Relationships and Related Transactions, and Director Independence	38
Item 14.	Principal Accountant Fees and Services	38
PART IV
Item 15.	Exhibits and Financial Statement Schedules	38
	Signatures	47
	Report of Independent Registered Public Accounting Firm	49
	Financial Statement Schedules	50

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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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Item 1. Business

General 

Corporate Structure and Business

PG&E Corporation, incorporated in California in 1995, is a holding company that conducts its business through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California.  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’s revenues are generated mainly through the sale and delivery of electricity and natural gas to customers.  The Utility served approximately 5.2 million electricity distribution customers and approximately 4.4 million natural gas distribution customers at December 31, 2012.  The Utility had approximately $52 billion in assets at December 31, 2012 and generated revenues of approximately $15 billion in 2012.  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 offices of PG&E Corporation and the Utility are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177.  PG&E Corporation’s telephone number is (415) 267-7000 and the Utility’s 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, 2012, which is attached to this report as Exhibit 13 (“2012 Annual Report”) and the Joint Proxy Statement relating to the 2013 Annual Meetings of Shareholders.  The 2012 Annual Report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  For a discussion of 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 information in the 2012 Annual Report under the headings “Cautionary Language Regarding Forward-Looking Statements” and “Risk Factors” which appear under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (“MD&A”).

Operational Improvements

The Utility’s electricity and natural gas businesses are each led by a senior executive who reports to the President of the Utility. During 2012, the Utility continued to build these organizations by adding new leaders with extensive industry expertise and expanding the Utility’s work force where needed to implement the Utility’s enhanced focus on safety and operational excellence.  Significant improvements were made to the Utility’s natural gas operations during 2012 to enhance safety, test and replace pipelines, modernize and upgrade the system, and search and validate records.  Much of this work was carried out under the Utility’s pipeline safety enhancement plan that was approved by the CPUC in late December 2012.  The Utility also continued work to implement the safety recommendations made by the National Transportation Safety Board (“NTSB”) in its 2011 investigative report on the rupture of one of the Utility’s natural gas transmission pipelines in San Bruno, California on September 9, 2010 (the “San Bruno accident”).  (For more information, see “Natural Gas Utility Operations” below.)   The Utility also undertook significant projects in 2012 to improve and modernize its electricity operations by repairing, replacing or upgrading equipment to improve reliability and safety.  In addition, the Utility continued the installation of advanced electric and gas meters throughout its service territory and took other steps to lay the foundation for the development of a “smart grid” to enable customers to have better control over their energy usage and costs, to integrate new

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sources of energy (such as distributed generation and storage, rooftop solar and other intermittent energy sources), and to enable the continued safe and reliable operation of the grid.  (For more information, see “Electric Utility Operations” below.)

Employees 

At December 31, 2012, PG&E Corporation and its subsidiaries had 20,593 regular employees, including 20,583 regular employees of the Utility.  Of the Utility’s regular employees, 12,492 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”).  There are two collective bargaining agreements with IBEW.   One IBEW collective bargaining agreement expires on December 31, 2014 and the other IBEW collective bargaining agreement expires on December 31, 2015.  The ESC collective bargaining agreement expires on December 31, 2014.  The SEIU collective bargaining agreement expires on July 31, 2013.

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.  This section and the “Ratemaking Mechanisms” section below summarize some of the more significant laws, regulations, and regulatory proceedings 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 PG&E Corporation and the Utility do not currently anticipate.

PG&E Corporation is a public utility holding company that is subject to the requirements of the Public Utility Holding Company Act of 2005 (“PUHCA”).  Under the PUHCA, 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 the PUHCA 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.

For discussion of specific pending regulatory proceedings and investigations that are expected to affect the Utility, see the information under the headings within MD&A entitled “Regulatory Matters” and “Natural Gas Matters” in the 2012 Annual Report, which information is incorporated herein by reference.

Federal Regulation

The Federal Energy Regulatory Commission

The FERC regulates the transmission of electricity 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 Corporation (“CAISO”), and the terms and rates of wholesale electricity sales.  The FERC has authority to impose penalties of up to $1 million 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 annual amount of revenue (“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.

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.  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, also performs a compliance audit of the Utility every three years.  In addition, the WECC and the NERC may perform

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spot checks or other interim audits, reports, or investigations.  The FERC also has authorized the WECC and the NERC to impose penalties up to $1 million per day, per violation.

The FERC also has adopted policies and rules to promote investment in energy infrastructure and lower costs for consumers through incentive ratemaking for transmission projects.  In addition, the FERC’s Order No. 1000 establishes electric transmission planning and cost allocation requirements for public utility transmission providers.  Order No. 1000 requires public utility transmission providers to improve transmission planning processes and allocate costs for new transmission facilities to the beneficiaries of those facilities.

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.

The Nuclear Regulatory Commission

The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility’s 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, seismic, 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.  For information about NRC matters affecting Diablo Canyon, including the status of the Utility’s relicensing application see the information under the heading within MD&A entitled “Regulatory Matters−Diablo Canyon Nuclear Power Plant” in the 2012 Annual Report, which information is incorporated herein by reference.

The Pipeline and Hazardous Materials Safety Administration

The Utility also is subject to regulations adopted by the federal 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.  Through a certification with PHMSA, the CPUC is authorized to enforce the federal pipeline safety standards over intrastate natural gas pipelines, as well as any state pipeline safety requirements that do not conflict with the federal requirements, through penalties and/or injunctive relief.

The National Transportation Safety Board

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 investigated the San Bruno accident and in August 2011 announced that it had determined the probable cause of the San Bruno accident placing the blame primarily on the Utility.  The NTSB report recommended that the Utility take certain actions to improve the safety of its gas transmission system.  The status of the Utility’s implementation of the NTSB’s recommendations is discussed under “Natural Gas Utility Operations” below.

State Regulation

The California Public Utilities Commission  

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 over the rates and terms and conditions of service for the Utility's electricity and natural gas distribution operations, electricity generation, and natural gas transportation and storage services.  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, rates 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 state laws that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas gathering, transmission, and distribution pipeline systems, and for the safe operation of such pipelines and equipment.  The CPUC has adopted many rules and regulations to

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implement state laws and policies, such as the laws relating to the development of renewable energy resources, demand response and public purpose programs, and the reduction of greenhouse gas (“GHG”) emissions.  The CPUC also has been delegated authority to enforce compliance with certain federal regulations related to the safety of natural gas facilities.  The CPUC has authority to impose penalties for violating these state and federal laws, orders, or regulations of up to $50,000 per violation, per day.  (See the discussion under the heading within MD&A entitled “Natural Gas Matters” in the 2012 Annual Report for information about the CPUC’s pending enforcement proceedings against the Utility relating to the Utility’s safety recordkeeping for its natural gas transmission system; the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density; and the Utility’s pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct that could have led to or contributed to the San Bruno accident, which discussion is incorporated herein by reference.)  

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.  The CPUC has imposed conditions that govern the relationship between the Utility and PG&E Corporation and other affiliates.  These conditions relate to finance, human resources, records and bookkeeping, and the transfer of customer information.  Among other conditions, the financial conditions provide that the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation’s Board of Directors (known as the “first priority” condition).  In addition, 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 CPUC has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations.

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 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 forecasts of 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 GHG and other emission limits.  The CARB also is responsible for adopting and enforcing regulations to meet 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 2013.  In October 2011, the CARB adopted its final “cap-and-trade” regulations to help gradually reduce GHG emissions.  In November 2012, the CARB held the first auction of GHG emission allowances under this “cap-and-trade” program. (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 agency

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that granted them if facts develop or events occur that differ significantly from the facts and projections assumed when they were granted.  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.  (For more information, see “Environmental Matters — Water Quality” below.)

The Utility has franchise agreements with 292 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.  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 of years, including an agreement with a large charter city.

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 in the Electricity Industry

At the federal level, the FERC is charged with developing rules to encourage fair and efficient competitive wholesale electric markets by employing best practices in market rules and reducing barriers to trade between markets and among regions.  (See “Regulatory Environment−Federal Regulation” above for a description of some of these rules.)  The FERC also has 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.  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 electric transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and standardizing interconnection procedures, and encourage investment in generation and transmission.

At the state level, the California Legislature mandated the restructuring of the California electricity industry beginning in 1998 to allow customers of the California investor-owned electric utilities to purchase electricity from a service provider other than the regulated utilities (the ability to choose an energy provider is referred to as “direct access”).  A market framework was established 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 California Power Exchange (“PX”).  As the 2000-2001 California energy crisis unfolded, direct access was suspended.  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 bankruptcy proceeding that was precipitated by the energy crisis, see Note 13: Resolution of Remaining Chapter 11 Disputed Claims, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.)

Current California law provides only limited opportunities for customers who receive “bundled” electricity service (i.e., electricity, transmission and distribution services) to choose to purchase electricity directly from an energy service provider other than the three California investor-owned electric utilities. As authorized by California law enacted in October 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 electric utilities to purchase electricity from independent electric service providers rather than from a utility. Effective April 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.

In addition, the Utility’s customers may, under certain circumstances, obtain power from a community choice aggregator (“CCA”) instead of from the Utility.  California law permits cities and counties and certain other public agencies to purchase and sell electricity for their local residents and businesses after they have registered as

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CCAs.  Under these arrangements, the Utility continues to provide distribution, metering, and billing services to the customers of the CCAs and remains the electricity provider of last resort for those customers.  The law provides that a CCA can procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility.  Under the CPUC’s rules, a surcharge is imposed on retail end-users of the CCA to prevent a shifting of costs to customers who continue to receive electricity from a utility. The law also authorizes the Utility to recover from each CCA any costs of implementing the program that are reasonably attributable to the CCA, and to recover from all customers any costs of implementing the program not reasonably attributable to a CCA.  Over 90,000 customers in Marin County are now receiving commodity service from the Marin Energy Authority, a CCA.

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 could pose challenges for traditional utilities.  In particular, technology-related cost declines and sustained federal or state subsidies could make the combination of “distributed generation” and storage a viable, cost-effective alternative to the Utility’s bundled electric service.  In addition, the levels of self-generation of electricity by customers (primarily solar installations) and the use of customer net energy metering, which allows self-generating customers to receive bill credits at the full retail rate, are increasing.

Although the CPUC has established ratemaking mechanisms that allow the Utility to collect some non-bypassable or fixed charges from those who procure electricity from alternate sources, rates for the Utility’s remaining customers could increase as alternative energy providers (CCAs or local government agencies) and alternative energy sources (self-generation and storage, distributed generation, electric vehicles) become more prevalent.  Increasing rate pressure on remaining customers could, in turn, cause more customers to seek alternative energy providers or sources, further exacerbating the Utility’s rate challenges.

Competition in the Natural Gas Industry

Under the FERC’s rules, interstate natural gas pipeline companies are required to divide their services into separate gas commodity sales, transportation, and storage services and must provide transportation service whether or not the customer (often a local gas distribution company) buys the natural gas from these companies.  The Utility’s natural gas pipelines are located within the State of California and are exempt from most of 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 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.  Non-core customers have access to capacity rights for firm service on the Utility’s natural gas pipeline, as well as interruptible (or “as-available”) services.  All services are offered on a nondiscriminatory basis to any creditworthy customer.  This market structure has resulted in a robust wholesale gas commodity market at the Utility’s “Citygate,” which refers to the non-physical interconnection between the big “backbone” gas transmission system and the smaller downstream local transmission systems.  The Utility’s gas transmission and storage system has operated under the CPUC-approved “Gas Accord” market structure since 1998 which largely mimics the regulatory framework required by the FERC for interstate gas pipelines. (See “Ratemaking Mechanisms” below.)

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 and U.S. Rocky Mountains natural gas delivered to northern California, relative to the total delivered cost of natural gas from the southwestern United States.  In general, when the total cost of western Canadian and U.S. Rocky Mountains natural gas delivered to northern California 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.

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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 conduct proceedings to determine the revenue requirements that the Utility is authorized to collect from its customers.  The CPUC determines the Utility’s revenue requirements associated with electricity and natural 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.

To develop retail rates, the revenue requirements are allocated among customer classes which are mainly residential, commercial, industrial, and agricultural.  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.

The Utility uses balancing accounts to keep track of its authorized revenue requirements, actual customer billings collected through rates, and actual costs incurred to provide electricity and natural gas services.  Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.  For more information regarding the Utility’s balancing accounts, see Note 3: Regulatory Assets, Liabilities and Balancing Accounts, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.

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 energy efficiency goals, instead of on the cost of providing service.

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 anticipated business and operational costs related to its electricity and natural gas distribution and electricity generation operations and to provide the Utility an opportunity to earn its authorized rate of return.  The CPUC generally conducts a GRC every three years.  Typical interveners in the Utility's GRC include the CPUC’s Division of Ratepayer Advocates and The Utility Reform Network.  In November 2012, the Utility filed its 2014 GRC application with the CPUC for rates effective from 2014 through 2016.  For more information see the heading within MD&A entitled “2014 General Rate Case” in the 2012 Annual Report, which information is incorporated herein by reference.  

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.

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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, natural gas transmission, and electricity generation assets.  The authorized capital structure that was in effect through 2012 consisted of 52% equity, 46% long-term debt, and 2% preferred stock.  Since 2008, the Utility’s authorized cost of capital has been subject to an adjustment mechanism that is triggered in a particular year if the 12-month October-through-September average of the applicable Moody's Investors Service utility bond index increases or decreases by more than 100 basis points from the benchmark.  If the adjustment mechanism is triggered, the Utility’s authorized ROE beginning on the next January 1st would be adjusted by one-half of the increase or decrease.  This mechanism did not trigger a change in the Utility’s authorized rates of return for 2012.

In December 2012, the CPUC issued a decision in the cost of capital proceeding that authorizes the Utility to maintain a capital structure consisting of 52% equity, 47% long-term debt, and 1% preferred stock beginning on January 1, 2013. (For more information see the section of MD&A entitled “2013 Cost of Capital Proceeding” in the 2012 Annual Report, which information is incorporated herein by reference.)

Rate Recovery of Costs of Electricity Generation Resources

Overview

California investor-owned electric utilities are required to use the principles of “least-cost dispatch” in managing electric generation resources to meet customer demand for electricity. The utilities are also responsible for procuring electricity required to meet customer demand, plus applicable reserve margins, that are not satisfied from their own generation facilities and existing electricity contracts.  To accomplish this, each utility must submit a ten-year procurement plan to the CPUC for approval.  Each procurement plan must be designed to reduce GHG emissions and use the State of California’s preferred loading order to meet the 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). The CPUC approved the Utility’s electricity procurement plan in January 2012 covering 2011 through 2020 and approved the Utility’s GHG compliance instrument procurement plan in April 2012.

California law allows electric utilities to recover the costs incurred in compliance with their CPUC-approved electricity procurement plans without further after-the-fact reasonableness review.  To the extent the Utility’s electricity purchases are not in compliance with the CPUC-approved plan, costs associated with those purchases may be disallowed. The Utility recovers its electricity procurement costs through the Energy Resource Recovery Account (“ERRA”), a balancing account authorized by the CPUC.  The ERRA tracks the difference between (1) billed and unbilled ERRA revenues and (2) electric procurement costs incurred under the Utility's authorized procurement plans.  To determine the rates used to collect ERRA revenues, each year, the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements, hedging, and generation fuel expense and approves a forecasted revenue requirement.  On December 20, 2012, the CPUC approved the Utility’s forecast of 2013 procurement costs and associated revenue requirement.  Changes in rates to reflect the approved revenue requirement became effective on January 1, 2013.  (The CPUC may adjust a utility’s retail electricity rates at any time when the forecasted aggregate over-collections or under-collections in the ERRA exceed five percent of its prior year electricity procurement revenues.)  The CPUC also performs an annual compliance review to ensure that (1) the Utility prudently administered the contracts that were entered into in accordance with its CPUC-approved procurement plans, (2) utilized the principles of least-cost dispatch in managing its electric generation resources, and (3) prudently operated its own generation facilities.  

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 procurement plan, the renewable energy mandate, 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 also recover any above-market costs through either (1) a non-bypassable customer charge 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 direct access customers and CCA customers under certain circumstances.  The non-bypassable charge can be imposed from the date of signing a power purchase agreement and can last for ten

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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 ten years on a case-by-case basis.  If a utility uses the net capacity cost allocation method, the net capacity costs are allocated for the term of the contract.  To use the net capacity allocation method, the CPUC must determine that a resource was needed to meet system or local area reliability needs for the benefit of all distribution customers.  The CPUC can decide whether to require an energy auction for resources subject to the net capacity cost allocation.

For renewable generation purchased from third parties under power purchase agreements, the Utility may also recover any above-market costs through the imposition of a non-bypassable charge on customers.

Costs of Utility-Owned Generation Resource Projects

The CPUC-authorized revenue requirements to recover the initial capital costs for utility-owned generation projects are recovered through 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.  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 Utility may recover any above-market costs associated with new utility-owned generation resources in a manner similar to the recovery of above-market costs for non-renewable generation purchases described above.  The recovery of above-market costs is typically addressed in the CPUC order approving a specific utility-owned generation project.

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 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 and are collected from retail electric customers receiving bundled service.

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.  See the information within MD&A entitled “FERC Transmission Owner Rate Case” in the 2012 Annual Report, which information is incorporated herein by reference.  

The Utility's transmission owner tariff includes several 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.  Another component consists of rates that reflect credits and charges from the CAISO 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 and charges related to the cost of providing service to existing transmission contract customers under specific contracts.  The CAISO also imposes a transmission access charge on the Utility for use of the CAISO-controlled electric transmission grid in serving its customers, which are recovered from the Utility’s retail customers as part of transmission rates.

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Natural Gas

Gas Safety Rulemaking Proceeding

The CPUC is conducting a rulemaking proceeding to adopt new safety and reliability regulations for natural gas transmission and distribution pipelines in California and the related ratemaking mechanisms.  As directed by the CPUC, in August 2011, the Utility filed its proposed pipeline safety enhancement plan to replace certain natural gas pipeline segments, install automatic or remote shut-off valves, and take other actions to modernize and upgrade its natural gas transmission system.  On December 20, 2012, the CPUC approved the Utility’s proposed plan but disallowed the Utility’s request for rate recovery of a significant portion of plan-related costs that the Utility forecasted it would incur over the first phase of the plan (2011 through 2014).  See the information under the heading within MD&A entitled “Natural Gas Matters−CPUC Gas Safety Rulemaking Proceeding” in the 2012 Annual Report, which information is incorporated herein by reference.

Natural Gas Transmission and Storage Rate Cases

The CPUC determines the Utility’s authorized revenue requirements and rates for its natural gas transmission and storage services in a separate rate case called the gas transmission and storage (“GT&S”) rate case.  The CPUC’s decision in the most recent GT&S rate case approved a settlement agreement, known as the Gas Accord V, which set the Utility’s rates and associated revenue requirements for natural gas transmission and storage services from January 1, 2011 through December 31, 2014.  (The Utility expects to file an application to begin the next GT&S rate case in September 2013.)  A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, 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 continues 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 38% of the total backbone capacity on the Utility’s system.  Core customers pay approximately 69% of the costs of the backbone capacity that is allocated to them through fixed reservation charges.

Local Transmission.  The local transmission revenue requirement is allocated approximately 66% to core customers and 34% 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 51% to core customers, 37% to non-core storage service, and 12% 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.

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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 recovers the cost of gas used in generation facilities as a cost of electricity that is recovered through electricity balancing accounts.)

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 natural gas 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 Utility retains the remaining amount of savings as incentive revenues, subject to a cap equal to 1.5% of total natural gas commodity costs.  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, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference).

Interstate and Canadian Natural Gas Transportation

The Utility has a number of agreements with interstate and Canadian third-party transportation service providers to transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada, the U.S. Rocky Mountains, and the southwestern United States) to the points at which the Utility's natural gas transportation system begins. These are governed by tariffs that detail rates, rules, and terms of service for the provision of natural gas 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 transportation costs the Utility incurs under these agreements are recovered through CPUC-approved rates as core natural gas procurement costs or as electricity procurement costs.  For more information, see the discussion below under “Natural Gas Utility Operations — Interstate and Canadian Natural Gas Transportation Services Agreements” below.

Electric Utility Operations

During 2012, the Utility made significant 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; to integrate more renewable energy resources; to increase capacity; and add new infrastructure to meet customer demand growth.  The Utility improved the reliability of its system by adding emergency capacity at substations, increasing distribution system automation, upgrading poor performing circuits, performing targeted asset replacement, and improving service restoration processes.  The Utility also has been working to accelerate pole replacement and maintenance of its overhead and underground electric facilities and to increase the use of wireless devices that allow the Utility to monitor the performance of the electric system and respond more quickly to power disruptions.

The Utility also substantially completed the installation of an advanced metering infrastructure throughout its service territory in 2012.  As of December 31, 2012, the Utility has installed approximately 8.9 million advanced electric and gas meters.  As permitted by CPUC rules, customers may choose not to have an advanced meter

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installed.  The new infrastructure uses SmartMeterTM technology that can measure energy use 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 communications network and transmitted to the Utility’s information system where the data is stored and used for billing and other Utility business purposes.

The Utility’s advanced metering infrastructure supports the development of a “smart grid” in California, part of a nationwide effort to improve and modernize the nation’s electric system by combining advanced communications and controls to create a responsive and resilient energy delivery network.  In March 2012, the Utility began incorporating the latest “smart grid” technology in parts of its service territory by installing automated switches that reduce outage duration and the number of customers affected by outages.  When an electrical outage occurs, these switches detect a short circuit, block power flow to the affected area, communicate with a central computer, and then quickly reroute power around the problem to keep as many customers powered as possible. Over the next several years, the Utility plans to undertake various “smart grid” projects and invest in “smart grid” technologies.

Electricity Resources

The Utility is required to maintain physical generating capacity adequate to meet its customers’ 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 in the most cost-effective way. The following table shows the percentage of the Utility’s total actual deliveries of electricity to customers in 2012 represented by each major electricity resource.

Total 2012 Actual Electricity Delivered – 76,205 GWh:

	Percent of Bundled Retail Sales
Owned Generation Facilities
Nuclear		23.3	%
Small Hydroelectric		1.2	%
Large Hydroelectric		9.7	%
Fossil fuel-fired		8.3	%
Solar		0.2	%
Total				42.7	%
Qualifying Facilities (1)
Renewable		4.4	%
Non-Renewable		9.8	%
Total				14.2	%
Irrigation Districts and Water Agencies
Small Hydroelectric		0.3	%
Large Hydroelectric		3.5	%
Total				3.8	%
Other Third-Party Purchase Agreements
Renewable		12.9	%
Large Hydroelectric		0.4	%
Non-Renewable		11.5	%
Total				24.8	%
Others, Net (2)				14.5	%
Total				100	%

                              (1)  Electric utilities are required under federal law to purchase energy and capacity from independent power producers with generation facilities (20 MW or less) that meet the definition of a qualifying facility (“QF”)

                                    under the Public Utility Regulatory Policies Act of 1978.  QFs primarily includeco-generation facilities that produce combined heat and power and renewable generation facilities.  For more information about the

                                    power purchase agreements that the Utility has entered into with QFs, see “QF Power Purchase Agreements,” below.

                              (2) This amount is mainly comprised of net CAISO open market purchases, offset by transmission and distribution related system losses.

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Owned Generation Facilities

At December 31, 2012, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below:

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	106	2,683
Helms pumped storage	Fresno	3	1,212
Hydroelectric subtotal:		109	3,895
Fossil fuel-fired:
Colusa Generating Station	Colusa	1	657
Gateway Generating Station	Contra Costa	1	580
Humboldt Bay Generating Station	Humboldt	10	163
CSU East Bay Fuel Cell	Alameda	1	1.4
SF State Fuel Cell	San Francisco	2	1.6
Fossil fuel-fired subtotal:		15	1,403
Photovoltaic:		10	102
Total		136	7,640

Diablo Canyon Power Plant.  The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2.  For the twelve months period ended December 31, 2012, the Utility’s Diablo Canyon power plant achieved an average overall capacity factor of approximately 90%.  The NRC operating license for Unit 1 expires in November 2024, and the NRC operating license for Unit 2 expires in August 2025.  For more information on matters affecting Diablo Canyon, see the section of MD&A entitled “Regulatory Matters−Diablo Canyon Nuclear Power Plant” in the 2012 Annual Report, which information is incorporated herein by reference.  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 2012 Annual Report, which information is incorporated herein by reference.

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 43.6 days.  The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

	2013	2014	2015	2016	2017
Unit 1
Refueling	-	February	September	-	April
Duration (days)	-	40	40	-	30
Startup	-	March	November	-	May
Unit 2
Refueling	February	September	-	May	-
Duration (days)	52	40	-	35	-
Startup	March	November	-	June	-

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Hydroelectric Generation Facilities. The Utility’s hydroelectric system consists of 109 generating units at 68 powerhouses, including the Helms pumped storage facility.  Most of the Utility’s hydroelectric generation units are classified as “large” hydro facilities, as their unit capacity exceeds 30 MW.  The Helms pumped storage facility consists of three motor/generator units.  During 2011, the Utility began inspections of all three units following reports of a significant failure of a similarly designed pumped storage generation unit in Austria that was apparently caused by cracks in the generator rotor poles due to metal fatigue.   The Utility completed inspections and repairs on each of the three units and returned them to service in 2012.

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.  The Utility is in the process of renewing hydroelectric licenses associated with capacity of approximately 1,137 MW and surrendering the hydroelectric license associated with the Kilarc-Cow Creek Project which has a capacity of 5 MW.  Although the original licenses associated with 880 MW of the 1,137 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process.  Licenses associated with approximately 3,002 MW of hydroelectric power will expire between 2013 and 2047.

Fossil Fuel-fired Generation Facilities. The Utility’s natural gas-fired generation facilities include the Colusa Generating Station, the Gateway Generating Station, and the Humboldt Bay generating station.  In addition, the Utility owns and operates three fuel cell sites in the Bay Area.  On December 20, 2012, the CPUC approved an amended purchase and sale agreement between the Utility and a third-party developer that provides for the construction of a 586-megawatt natural gas-fired facility in Oakley, California  that would be acquired by the Utility no sooner than January 1, 2016. 

Photovoltaic Facilities. In April 2010, the CPUC approved the Utility’s five-year program for the development of up to 250 MW of solar photovoltaic (“PV”) facilities to be owned and operated by the Utility, along with entering into power purchase agreements for an additional 250 MW of PV facilities to be developed by third parties.  Under the PV program, Utility-owned PV facilities with an aggregate of 100 MW are operational, and an additional 50 MW are under construction and expected to become operational in 2013.  The operational PV facilities include, the Five Points solar station (15 MW), the Westside solar station (15 MW), the Stroud solar station (20 MW), the Huron solar station (20 MW), the Cantua solar station (20 MW), and the Giffen solar station (10 MW).   All of these facilities are located in Fresno County.  The PV facilities under construction are the Gates solar station (20 MW), the West Gates solar station (10 MW) and the Guernsey solar station (20 MW).  The Gates and West Gates solar stations are located in Fresno County; the Guernsey solar station is located in Kings County.

In December 2012, the Utility sought CPUC approval to terminate the PV program early.  If approved, the Utility will not pursue the development of the remaining 100 MW of Utility-owned PV facilities over the remaining two years of the program, but instead will procure this capacity through the CPUC’s Renewable Auction Mechanism (“RAM”) process.  Additionally, the Utility proposed to solicit the remaining 152 MW of capacity to be provided under power purchase agreements through the RAM process rather than through the PV program.

Generation Resources from Third Parties

QF Power Purchase Agreements.  Under the Public Utility Regulatory Policies Act (“PURPA”) of 1978 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”).  In June 2011, the FERC approved the California investor-owned utilities’ joint application to terminate their obligation under PURPA to purchase QF energy and capacity from facilities exceeding 20 MW.  QFs primarily includeco-generation facilities that produce combined heat and power and renewable generation facilities.  As of December 31, 2012, the Utility had power purchase agreements with 180 operating QFs for approximately 3,000 MW of capacity.  The majority of this capacity is from cogeneration facilities and the remainder is from renewable generation facilities.  Agreements for approximately 2,700 MW expire at various dates between 2013 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.  No single QF accounted for more than 5% of the Utility’s 2012 electricity deliveries.

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Irrigation Districts and Water Agencies.  The Utility also has entered into agreements with various irrigation districts and water agencies to purchase hydroelectric power.  These agreements require the Utility to make semi-annual fixed minimum payments as well as variable payments based on the operating and maintenance costs incurred by the irrigation districts and water agencies.  These contracts will expire on various dates between 2013 and 2030.

Other Third-Party Power Purchase Agreements.  The Utility has entered into several power purchase agreements for renewable and conventional generation resources, including tolling agreements and resource adequacy agreements.

For more information regarding the Utility’s power purchase agreements, see Note 15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.

Renewable Generation Resources

Renewable generation resources include bioenergy such as biogas and biomass, small hydroelectric, wind, solar, and geothermal energy.  California’s Renewables Portfolio Standard (“RPS”) program gradually increases the amount of renewable energy that load-serving entities, such as the Utility, must deliver to their customers from an average of at least 20% of their total retail sales in the years 2011-2013 to 33% of their total retail sales in 2021 and thereafter.  For more information regarding the new RPS program, see the section of MD&A entitled “Environmental Matters – Renewable Energy Resources” in the 2012 Annual Report, which information is  incorporated herein by reference.

During 2012, most renewable energy deliveries resulted from third party power purchase agreements and QF agreements.  Additional renewable resources included the Utility’s small hydroelectric and solar facilities and certain irrigation district contracts (small hydroelectric facilities).  (Under California law only small hydroelectric generation resources (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 the 30-MW threshold and do not qualify as RPS-eligible resources.)

Total 2012 renewable deliveries are stated in the table below.

Type	GWh	% of Bundled Load
Biopower	3,373	4.4%
Geothermal	3,803	5.0%
Wind	4,338	5.7%
Small Hydroelectric	1,812	2.4%
Solar	1,171	1.5%
Total	14,497	19.0%

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 2012 Annual Report, which information is incorporated herein by reference.

Electricity Transmission 

At December 31, 2012, the Utility owned approximately 18,100 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV.  The Utility also operated 91 electric transmission substations with a capacity of approximately 60,800 MVA.  The Utility’s electric transmission system is interconnected with electric power systems in the WECC, which includes many western states, Alberta and British Columbia, Canada, and parts of Mexico.

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 its own 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

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the Utility entered into with these entities before the CAISO commenced operation in 1998.  In addition, under the mandatory reliability standards implemented by the FERC, 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 under “The Utility’s Regulatory Environment — Federal Regulation” above.

During 2012, the Utility upgraded several critical substations and re-conductored some transmission lines to improve maintenance and operating flexibility, reliability and safety, including the installation or replacement of 9 transmission substation banks.  The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system and increase capacity in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, and to improve system reliability.

Electricity Distribution

The Utility's electricity distribution network consists of approximately 141,000 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead), 58 transmission-switching substations, and 601 distribution substations.   The Utility’s distribution network interconnects with  the Utility’s transmission system primarily at transmission switching substations and 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.

In 2012, the Utility replaced more than 130,000 feet of underground cable, primarily in San Francisco and Oakland, replaced 98,000 feet of overhead wire, and installed or replaced 39 distribution substation transformer banks to improve reliability and provide capacity to accommodate growing demand.  The Utility plans to continue performing work to improve the reliability and safety of its electricity distribution operations in 2013.

Electricity Operating Statistics

The following table shows certain of the Utility’s operating statistics from 2008 to 2012 for electricity sold or delivered, including the classification of revenues by type of service.

	2012	2011	2010	2009	2008
Customers (average for the year)	5,214,170	5,188,638	5,155,724	5,137,240	5,129,427
Deliveries (in GWh) (1)	86,113	81,255	79,634	72,385	74,783
Revenues (in millions):
Residential	$ 4,953	$ 4,778	$ 4,795	$ 4,759	$ 4,656
Commercial	4,735	4,732	4,823	4,538	4,413
Industrial	1,408	1,379	1,424	1,392	1,400
Agricultural	901	692	736	770	727
Public street and highway lighting	79	77	79	74	75
Other	(11)	94	(1,178)	(1,700)	(863)
Subtotal	12,065	11,752	10,679	9,833	10,408
Regulatory balancing accounts	(51)	(151)	(35)	424	330
Total electricity operating revenues	$12,014	$11,601	$ 10,644	$ 10,257	$ 10,738
Other Data:
Average annual residential usage (kWh)	5,961	6,799	6,843	6,953	7,007
Average billed revenues (per kWh):
Residential	$ 0.1594	$ 0.1548	$ 0.1560	$ 0.1524	$ 0.1480
Commercial	0.1449	0.1441	0.1468	0.1377	0.1296
Industrial	0.917	0.951	0.988	0.940	0.867
Agricultural	0.1458	0.1475	0.1451	0.1327	0.1300
Net plant investment per customer	$ 4,919	$ 5,045	$ 4,728	$ 4,336	$ 3,994

(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

During 2012, the Utility has taken many immediate and longer-term steps to improve the safety and reliability of its natural gas transmission system, including performing extensive pipeline testing and monitoring, and replacing and upgrading equipment.  Much of this work is part of the Utility’s pipeline safety enhancement plan (“PSEP”), approved by the CPUC in December 2012, to meet the new, industry-wide safety standards for gas transmission systems.  (See the information within MD&A under the heading “Natural Gas Matters” in the 2012 Annual Report, which information is incorporated herein by reference.)

In 2012, as part of the PSEP pipeline modernization program, the Utility confirmed the strength of 202 miles of transmission pipeline through hydrostatic pressure tests or records verification, installed 46 automated or remote-controlled valves, replaced 40 miles of transmission pipeline, and retrofitted 78 miles of transmission pipeline to accommodate in-line inspection tools.  Since work on the program began in 2011, the Utility has also collected and digitized more than 3.5 million pipeline records, which includes validating the Maximum Allowable Operating Pressure (“MAOP”) for more than 89 percent of its gas transmission system (and 100 percent of the 2,088 miles of the Utility’s transmission pipelines in populated areas).

The Utility is also improving operations by utilizing modern tools and technologies.  In 2012, the Utility began demonstrating a new car-mounted natural gas leak detection device, which is much more sensitive than traditional instruments. The Utility also began using an advanced hand-held leak-detection instrument that uses infrared technology to pinpoint methane gas without false alarms from other gases. This technology can detect and grade leaks at the same time.  In addition, the Utility improved its supervisory controls and data acquisition system (“SCADA”) to better detect pipeline leaks and breaks and improved its integrity management program, including incorporating new analysis tools to identify and assess risks to pipeline integrity.

For the distribution system, the Utility has implemented a new distribution integrity management program designed to enhance operations and improve the overall safety of the gas distribution system.  In 2012, the Utility replaced 23 miles of Aldyl-A plastic pipeline and identified another 150 miles to be replaced over the next two years. It also updated the geographic information system with information on more than 5,500 miles of Aldyl-A pipeline, including additional pipeline and service attribute information.  The Utility also completed additional distribution leak surveys in 2012, in addition to complying with regular distribution leak survey requirements.

Many of these improvement efforts satisfy recommendations made to the Utility by the NTSB and the CPUC in 2010 and 2011.  In the first half of 2012, the Utility was able to officially close out four of the twelve NTSB recommendations. In January 2013, the Utility requested closure on three more recommendations. The Utility continues to make significant progress on the remaining longer-term recommendations, and the NTSB stated in September 2012 that the Utility’s progress was acceptable.

In December 2012, the CPUC accepted the gas safety plans submitted by each gas corporation in California, including the Utility, to describe each gas corporation’s programs, plans, and initiatives, to increase the safety and reliability of their natural gas operations.  The plans were submitted in compliance with California Senate Bill 705, enacted in October 2011, which requires each gas corporation subject to CPUC jurisdiction to develop and implement a plan for the safe and reliable operation of its gas pipeline system. The new law required the CPUC to review the plans and accept, modify, or reject each plan by December 31, 2012.  The CPUC has ordered the Utility, as well as the other gas corporations, to submit modifications to their plans by June 2013 and to continually review, revise and update their plans as required by emerging issues, industry practices, and state and federal regulators.

Natural Gas System Assets

The Utility owns and operates an integrated natural gas transportation, storage, and distribution system that includes most of northern and central California.  At December 31, 2012, the Utility’s natural gas system consisted of approximately 42,400 miles of distribution pipelines, approximately 6,400 miles of backbone and local transmission pipelines, and various storage facilities. The Utility owns and operates eight natural gas compressor stations which receive, store and move natural gas through the Utility’s pipelines.  (The Utility has incurred significant environmental liabilities related to some of its compressor stations. See “Environmental Matters” below.)  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

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fields to the Utility’s local transmission and distribution systems.  The Utility’s Line 300 interconnects with pipeline systems located in the U.S. Southwest and the Rocky Mountains that are owned by third parties (Transwestern Pipeline Company, El Paso Natural Gas Company, Questar Southern Trails Pipeline Company, and Kern River Pipeline Company).  Line 300 has a receipt capacity of approximately 1.1 Bcf per day.  The Utility’s Line 400/401 interconnects at the California-Oregon border with the pipeline systems owned by Gas Transmission Northwest Corporation (“GTN”) and Ruby Pipeline, LLC.  This line has a receipt capacity at the border of approximately 2.2 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.

The Utility owns and operates three underground natural gas storage fields connected to the Utility’s transmission and storage system and has a 25% interest in the new Gill Ranch Storage Field.  These storage fields and the Utility’s Gill Ranch share have a combined firm capacity of approximately 48.7 Bcf.  In addition, three independent storage operators are interconnected to the Utility's northern California transportation system.

Natural Gas Services

The CPUC divides the Utility’s on-system natural gas customers into two categories for the purpose of determining service reliability: 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 small commercial natural gas customers.  The non-core customer class is comprised of industrial, large commercial, and electric generation natural gas customers.  In 2012, core customers represented more than 99% of the Utility’s total natural gas customers and 36% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total natural gas customers and 64% of its total natural gas deliveries.In addition to deliveries discussed above, the Utility delivers gas to off-system customers (i.e., outside of the Utility’s service territory) and to third-party natural gas storage 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 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 96% of core customers, representing over 83% of the annual core market demand, receive bundled natural gas service from the Utility.

The Utility does not provide procurement service to large non-core customers such as electricity generators, QF co-generators, enhanced oil recovery customers, refiners, and other large non-core customers.  However, some smaller non-core customers are permitted to elect to receive core service, including procurement service, from the Utility if they agree to receive such service for a minimum of five years.  Core service to non-core customers is subject to these restrictions to protect core procurement customers from price increases that could otherwise result if the Utility incurred costs to reinforce its pipeline system and take other measures to provide core service reliability on a short-term basis to serve new load from non-core customers.

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, energy efficiency measures, or changes in their consumption levels.  The Utility’s results of operations can be affected, however, 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 the remainder from non-core customers.

Natural Gas Supplies

The Utility purchases natural gas to serve its 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 2012, the Utility purchased approximately 247,792 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

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represented approximately 10% of the total natural gas volume the Utility purchased during 2012.

Interstate and Canadian Natural Gas Transportation Services Agreements

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 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 two firm transportation agreements with GTN for these services.  In addition, the Utility has firm transportation agreements with Ruby Pipeline, LLC to transport this gas from the U.S Rocky Mountains to the interconnection point with the Utility’s natural gas transportation system in the area of Malin, Oregon, at the California border, and firm transportation agreements with Transwestern Pipeline Company, LLC 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.

Natural Gas Deliveries

The total volume of natural gas delivered to on-system customers during 2012 was approximately 945 MMDth.  The following table shows the percentage of the Utility’s total 2012 natural gas deliveries represented by each of the Utility’s major customer classes.

Residential Customers	20%
Transport-only Customers (non-core)	75%
Commercial Customers	5%

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 2012 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 2008 through 2012 (excluding subsidiaries) for natural gas, including the classification of revenues by type of service.

	2012	2011	2010	2009	2008
Customers (average for the year)	4,353,278	4,327,407	4,295,741	4,271,007	4,269,165
Gas purchased (MMcf)	247,792	279,157	270,228	264,314	260,315
Average price of natural gas purchased	$ 2.45	$ 3.69	$ 4.07	$ 3.57	$ 7.51
Bundled gas sales (MMcf):
Residential	185,376	201,109	195,195	195,217	198,699
Commercial	47,341	52,230	53,921	57,550	63,934
Total	232,717	253,339	249,116	252,767	262,633
Revenues (in millions):
Bundled gas sales:
Residential	$ 1,852	$ 2,089	$ 1,991	$ 1,953	$ 2,574
Commercial	383	464	474	496	792
Regulatory balancing accounts	221	295	305	289	221
Other	66	102	49	55	(30)
Bundled gas revenues	2,522	2,950	2,819	2,793	3,557
Transportation service only revenue	499	400	377	349	333
Operating revenues	$ 3,021	$ 3,350	$ 3,196	$ 3,142	$ 3,890
Selected Statistics:
Average annual residential usage (Mcf)	45	49	48	48	49
Average billed bundled gas sales revenues per Mcf:
Residential	$ 9.99	$ 10.39	$ 10.20	$ 10.00	$ 12.95
Commercial	8.09	8.89	8.79	8.62	12.38
Net plant investment per customer	$ 1,696	$ 1,721	$ 1,637	$ 1,557	$ 1,344

Public Purpose and Customer Programs

California law has historically required the CPUC to authorize certain levels of funding for programs related to energy efficiency, research and development, and renewable energy resources through the collection of an electric public goods charge.  The legislation authorizing the public goods charge expired on January 1, 2012.  The CPUC has ordered the Utility to continue to collect in electric rates the amounts that were previously funded through the public goods charge for energy efficiency and established an energy program investment charge to support ongoing energy efficiency and research and development.  Gas public interest research continues to be funded through the gas public purpose program surcharge.  California law requires the CPUC to authorize funding for the California Solar Initiative and other self-generation programs, as discussed under “Self-Generation Incentive Program and California Solar Initiative,” below.  Additionally, the CPUC has authorized funding for energy savings assistance and demand response programs.  For 2012, the Utility collected authorized revenue requirements of $688 million from electric customers and $169 million from gas customers to fund public purpose and other programs.

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Energy Efficiency Programs

The Utility’s energy efficiency programs are designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances, other energy-using equipment and energy management products to meet energy savings goals in California.  The CPUC has authorized a total of $823 million to fund the Utility’s 2013 and 2014 energy efficiency programs, including programs administered by the Marin Energy Authority, a CCA, and a regional network of San Francisco Bay area cities and counties.

On December 20, 2012, the CPUC approved a new energy efficiency incentive mechanism to reward the Utility and other California energy utilities for the successful implementation of their 2010-2012 energy efficiency programs.  The mechanism provides each utility with an earnings rate composed of a 5% management fee based on qualified program expenditures and an additional performance bonus of up to 1%.  The Utility’s earnings rate for the 2010-2012 energy efficiency program cycle is 5.68%.  The CPUC awarded the Utility $21 million for the successful implementation of the Utility’s 2010 energy efficiency programs.  The CPUC decision also established the process that is expected to apply to incentive claims for program years 2011 and 2012.  After the CPUC completes its audit of the utilities’ 2011 program expenditures, the utilities must file their incentive claims in the third quarter of 2013 for approval by the CPUC in the fourth quarter of 2013.  Similarly, the utilities will file their incentive claims based on the CPUC-audited 2012 program expenditures in the third quarter of 2014 for approval by the CPUC in the fourth quarter of 2014.

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.

Demand Response Programs

Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use.  In April 2012, the CPUC authorized the Utility to collect $192 million to fund its 2012-2014 demand response programs.  Due to the timing of the decision, the CPUC authorized the Utility to recover both 2012 and 2013 program costs through customer rates collected in 2013.

Self-Generation Incentive Program and California Solar Initiative

The Utility administers the self-generation incentive program authorized by the CPUC to provide incentives to electricity and gas 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.  In December 2011, the CPUC approved continuing annual funding for the self-generation incentive program of $36 million through 2014, with any carryover funds to be administered through 2015.  The Utility also administers the California Solar Initiative in its service territory.  The CPUC has authorized the Utility to collect approximately $1.1 billion from 2007 through 2016 to fund customer incentives for the installation of retail solar energy projects to serve onsite load, as well as to fund research, development, and demonstration activities, and administration expenses.  The current overall objective of this initiative is to install 3,000 MW (through both California investor-owned electric utilities and municipal electric utilities) through 2016.

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

The CPUC has authorized the Utility to collect approximately $469 million to support the Utility’s energy efficiency programs for low-income and fixed-income customers over 2012 through 2014.  The Utility also provides 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.  During any given year, the extent of the subsidy for customers collectively depends upon the number of customers participating in the program and their actual energy usage.  In 2012, the amount of this subsidy was approximately $851 million.  The CPUC also authorized the Utility to recover approximately $45 million in administrative costs relating to the CARE subsidy through 2014.

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Environmental Matters

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 under “Recovery of Environmental Remediation Costs” below.

Air Quality and Climate Change

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 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.

Federal Regulation.  At the federal level, the U.S. Environmental Protection Agency (“EPA”) is charged with implementation and enforcement of the Clean Air Act.  Although there have been several legislative attempts to address climate change through imposition of nationwide regulatory limits on GHG emissions, 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.

State Regulation.  AB 32 requires the gradual reduction of state-wide GHG emissions to the 1990 level by 2020. The CARB is the state agency charged with monitoring GHG levels and adopting regulations to implement and enforce AB 32.  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.  The CARB has approved various regulations to implement AB 32, including a state-wide, comprehensive “cap and trade” program that sets gradually declining limits (or “caps”) on the amount of GHGs that may be emitted by the major sources of GHG emissions.

The cap and trade program’s first two-year compliance period, which began January 1, 2013, applies to the electricity generation and large industrial sectors.  The next two-year compliance period, from January 1, 2015 through December 31, 2017, will expand to include the natural gas supply and transportation sectors, effectively

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covering all the capped sectors until 2020.  Each year the CARB will issue emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHGs emissions allowed for that year.  Emitters can obtain allowances from the CARB at quarterly auctions held by the CARB or from third parties on the secondary market for trading GHG allowances.  The CARB’s first quarterly auction was held on November 14, 2012. Emitters (also known as covered entities) are required to obtain and surrender allowances equal to the amount of their GHGs emissions within a particular compliance period. Emitters may also meet up to 8% of their compliance obligation through the purchase of “offset credits” which represent GHG emissions abatement achieved in sectors that are not subject to the cap.  For more information about the cap-and trade program, see the section of MD&A entitled “Environmental Matters” in the 2012 Annual Report, which information is incorporated herein by reference.

Increasing use of renewable energy supplies also is expected to help reduce GHG emissions in California.  In April 2011, the California Governor signed legislation that requires load-serving entities, such as the Utility, to gradually increase the amount of renewable energy delivered to their customers to at least 33% of the total amount of electricity retail sales by 2020.  (See “Electricity Resources” above.)  In December 2011, the CPUC approved various regulations to implement the new law, including the establishment of renewable energy targets for each compliance period.  (For more information, see “Renewable Generation Resources” above.)

Climate Change Mitigation and Adaptation Strategies.  During 2012, 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 parts of the Sierra Nevada Mountains.  This impact could, in turn, affect the Utility’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, 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 rather than snow, 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 hydroelectric generation with electricity from other sources, including GHG-emitting natural gas-fired power plants.

With respect to natural gas operations, safety-related pipeline hydrotesting, as well as normal pipeline maintenance, releases the GHG methane to the atmosphere. The Utility has taken steps to reduce the release of methane by implementing techniques including drafting and cross-compression. In addition, the Utility continues to replace a substantial portion of its older cast iron and steel gas mains with new pipe, which reduces leakage.

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 result from 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.  As a result of the time necessary for a thorough, third-party verification of the Utility’s GHG emissions, emissions data for 2011 are the most recent data available.  Since 2009, the Utility has complied with AB 32’s annual GHG emissions reporting requirements, reporting combustion emissions from its electric generation facilities and natural gas compressor stations to the CARB.  (For information about the sources of electric generation that the Utility delivered to customers in 2012, see “Electric Utility Operations− Electricity  Resources” above.)   Consistent with Utility practice since 2002, the Utility also voluntarily reported its 2011 GHG emissions to The Climate Registry (“TCR”), a non-profit organization that has a reporting and measurement standard applicable to most industry sectors across North America.  Reporting to TCR enables the Utility to publicly report GHG emissions not covered by mandatory reporting requirements.  The Utility’s third-party verified voluntary GHG

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inventory for 2011 totaled more than 50 million metric tonnes of CO2-equivalent (“CO2-e”), which includes approximately 33 million metric tonnes CO2-e from customer natural gas use.

Beginning with its 2010 emissions, the Utility also reported the GHG emissions from its facilities and operations to the EPA under its mandatory reporting requirements. PG&E Corporation and the Utility also publish third-party-verified GHG emissions data in their annual Corporate Responsibility and Sustainability Report.

2011 Emissions Reported to the California Air Resources Board

For its 2011 emissions, the Utility began reporting the GHG emissions from natural gas supplied to customers and the fugitive emissions from its natural gas distribution system and compressor stations. The following table shows the GHG emissions data the Utility reported to the CARB under AB 32.

Source	Amount (metric tonnes CO2 – equivalent)
Fossil Fuel-Fired Plants (1)	2,025,543
Natural Gas Compressor Stations (2)	258,446
Distribution Fugitive Natural Gas Emissions	224,298
Customer Natural Gas Use  (3)	39,049,732
Total	41,558,019

(1) Includes nitrous oxide (“N2O”) and methane (“CH4”) emissions from the Utility’s generating stations; does not include de minimis emissions.

(2) Includes compressor stations emitting more than 25,000 metric tonnes of CO2-e annually; does not include de minimis emissions.

(3) Includes emissions from the combustion of natural gas delivered to all entities on the Utility’s distribution system, with the exception of gas delivered to other natural gas local distribution companies. This figure does not represent the Utility’s compliance obligation under AB 32, which will be equivalent to the above reported value less the fuel that is delivered to covered entities as calculated by the CARB.

Benchmarking GHG Emissions for Delivered Electricity

The Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2011 was 393 pounds of CO2 per MWh. The Utility’s 2011 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)	1,216
California’s Average (1)	659
Pacific Gas and Electric Company (2)	393

                                               (1) Source: Environmental Protection Agency eGRID 2012 Version 1.0, which contains year 2009 information configured to reflect the electric power industry's current structure as of May 10, 2012.  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 more than 40% of the Utility’s delivered electricity in 2011. The Utility’s fossil fuel-fired generation comprised approximately 6% of the Utility’s delivered electricity in 2011.

	2011	2010
Total NOx Emissions (tons)	144	904
NOx Emissions Rates (pounds/MWh)
Fossil Fuel-Fired Plants	0.06	0.49
All Plants	0.008	0.06
Total SO2 Emissions (tons)	12	42
SO2 Emissions Rates (pounds/MWh)
Fossil Fuel-Fired Plants	0.005	0.023
All Plants	0.0007	0.003
Total CO2 Emissions (metric tons)	2,024,206	1,545,892
CO2 Emissions Rates (pounds/MWh)
Fossil Fuel-Fired Plants	875	943
All Plants	126	106
Other Emissions Statistics
Sulfur Hexafluoride (“SF6”)  Emissions
Total SF6 Emissions (metric tons CO2-            equivalent)	70,052	69,066
SF6 Emissions Leak Rate	1.7%	1.8%

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Water Quality

Section 316(b) of the federal Clean Water Act requires 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.  On April 20, 2011, the EPA published draft regulations that propose specific reductions for impingement (which occurs when larger organisms are caught on water filter screens) and provide a case-by-case site specific assessment to establish compliance requirements for entrainment (which occurs when organisms are drawn through the cooling water system).  The proposed site specific assessment allows for the consideration of a variety of factors including social costs and benefits, energy reliability, land availability, and non-water quality adverse impacts.  The draft regulations were subject to public comment.  In June 2012, the EPA issued a Notice of Data Availability proposing changes to the draft regulations which, if adopted, would provide more flexibility in complying with some of the requirements.  The EPA is required to issue final regulations by July 2013.

On May 4, 2010, the California Water Resources Control Board (“California 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 California Water Board in developing its policy.  The policy also allows other compliance measures to be taken 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.”  The policy also established a nuclear review committee to evaluate the feasibility and cost of alternative technologies for nuclear plants.  The committee’s consultant, Bechtel, must complete an assessment for the California Water Board’s review by October 2013.  Upon review of the feasibility assessment, if the California 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.  If the California Water Board requires the installation of cooling towers that the Utility believes are not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon, may need to procure substitute power, and may incur a material charge.  The Utility would seek to recover such costs in rates.  The Utility’s Diablo Canyon operations must be in compliance with the California Water Board’s policy by December 31, 2024.

Hazardous Waste Compliance and Remediation

The Utility's facilities are subject to the requirements issued by the EPA under the federal 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

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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, 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 has a comprehensive program in place to comply with federal, state, and local laws and regulations related to hazardous materials and hazardous waste compliance, remediation activities, and other environmental requirements.  The Utility assesses and monitors, on an ongoing basis, measures that may be necessary to comply with these laws and regulations and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the California Department of Toxic Substances Control (“DTSC”), several California regional water quality control boards, and various other federal, state, and local agencies.

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; 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 centers, 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.

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 the sections within MD&A entitled “Environmental Matters,” “Critical Accounting Polices,” and Note 15:  Commitments and Contingencies−Environmental Remediation Contingencies, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.

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.  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 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 $51 million in 2012 on these sites.

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

26

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 is responsible for remediating this groundwater contamination and for abating the effects of the contamination on the environment.  The Utility has incurred significant environmental liabilities associated with these sites.  For more information about the Utility’s remediation and abatement efforts and related liabilities, see Note 15: Commitments and Contingencies−Environmental Remediation Contingencies of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.

Recovery of Environmental Remediation Costs

The CPUC has authorized the Utility to recover most of its environmental remediation costs through various ratemaking mechanisms, subject to exclusions for certain sites, such as the Hinkley natural gas compressor site, and subject to limitations for certain liabilities such as amounts associated with fossil fuel-fired generation facilities formerly owned by the Utility.  For more information, see Note 15: Commitments and Contingencies−Environmental Remediation Contingencies of the Notes to the Consolidated Financial Statements in the 2012 Annual Report which information is incorporated herein by reference.

Nuclear Fuel Disposal

Under the Nuclear Waste Policy Act of 1982, the DOE and electric utilities with commercial nuclear power plants were authorized to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste by January 1998, in exchange for fees paid by the utilities.  The DOE has been unable to meet its contractual obligation with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and the retired nuclear facility at Humboldt Bay Unit 3.  As a result, the Utility constructed an interim dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024, and a separate facility at Humboldt Bay.  The Utility and other nuclear power plant owners sued the DOE to recover the costs that they incurred to construct interim storage facilities for spent nuclear fuel. 

On September 5, 2012, the U.S. Department of Justice and the Utility executed a settlement agreement that awarded the Utility $266 million for spent fuel storage costs incurred through December 31, 2010.  For more information, see Note 15: Commitments and Contingencies−Environmental Remediation Contingencies of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.  Considerable uncertainty continues to exist regarding when and whether the DOE will meet its contractual obligation to the Utility and other nuclear power plant owners to dispose of spent fuel.

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 files an application with the CPUC every three years requesting approval of the Utility’s estimated decommissioning costs and authorization to recover the estimated costs through rates.  Nuclear decommissioning charges collected through rates are held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit.   (See the discussion of the 2012 Nuclear Decommissioning Cost Triennal Proceeding in Note 2: Summary of Significant Accounting Policies of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.)

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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.

Item 1A.  Risk Factors

A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility appears within MD&A under the heading “Risk Factors” in the 2012 Annual Report, which information is incorporated herein by reference.

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, which are described above under “Electric Utility Operations” and “Natural Gas Utility Operations” which information is incorporated herein by reference.  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.  In March and September 2012, the Utility entered into 10-year facility lease agreements for 250,000 and 145,000 square feet of office space, respectively, in San Ramon, California.  The Utility also recently entered into a lease agreement for a new 12,000 square foot data center located near Sacramento, California.  In total, the Utility occupies 10.8 million square feet of real property, including 8.6 million square feet that the Utility owns.  Of the 10.8 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 currently owns approximately 167,000 acres of land, including approximately 140,000 acres of watershed lands.  As part of the settlement agreement entered into by PG&E Corporation and the Utility to resolve the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code, the Utility agreed to protect its watershed lands with conservation easements or equivalent protections, and/or donate up to approximately 75,000 acres of its watershed lands to public entities or qualified non-profit conservation organizations.   (The Utility will not donate watershed lands that contain the Utility's or a joint licensee's hydroelectric generation facilities or is otherwise used for utility operations, but this land may be encumbered with conservation easements.) The Utility formed a non-profit organization, 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 watershed lands.  The Council is governed by an 18-member board of directors, one of whom wasappointedby the Utility.  The other members  represent 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 Council’s goal is to implement thetransactions contemplated in the LCP over the next few years, subject to obtaining any requiredpermits andapprovals fromthe FERC,the CPUC, and other governmental agencies.

PG&E Corporation also leases approximately 82,000 square feet of office space from a third party in San Francisco, California, of which 40,000 square feet will expire in 2014 and the remaining in 2022.

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: Commitments and Contingencies−Legal and Regulatory Contingencies, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.

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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 Regional Water Quality Control Board (“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.

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 permit.

At its July 10, 2003 meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely.  Several Central Coast Board members indicated that they no longer supported the settlement agreement, 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.

In addition, the California Water Board’s policy on once-through cooling and regulations that are expected to be issued by the EPA in July 2013 could affect future negotiations between the Central Coast Board and the Utility regarding the status of the 2003 settlement agreement. (See “Item 1. Business−Environmental Matters−Water Quality” above.)

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

Litigation Related to the San Bruno Accident and Natural Gas Spending

At December 31, 2012, approximately 140 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, had been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 450 plaintiffs.  The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages.  These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court.  The trial of the first group of remaining cases began on January 2, 2013 with pretrial motions and hearings.  On January 14, 2013, the court vacated the trial and all pending hearings due to the significant number of cases that have been settled outside of court.  The court has urged the parties to settle the remaining cases.   As of February 8, 2013, the Utility has entered into settlement agreements to resolve the claims of approximately 140 plaintiffs.  It is uncertain whether or when the Utility will be able to resolve the remaining claims through settlement.

Additionally, in October 2010, a purported shareholder derivative lawsuit was filed following the San Bruno accident 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, relating to the Utility’s natural gas business. The case has been coordinated with the other cases in the San Mateo County Superior Court.  The judge has ordered that proceedings in the derivative lawsuit be delayed until further order of the court.  On February 7, 2013, another purported shareholder derivative lawsuit was filed in U.S. District Court for the Northern District of California to seek recovery on behalf of PG&E Corporation for alleged breaches of fiduciary duty by officers and directors, among other claims. 

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In addition, on August 23, 2012, a complaint was filed in the San Francisco Superior Court against PG&E Corporation and the Utility (and other unnamed defendants) by individuals who seek certification of a class consisting of all California residents who were customers of the Utility between 1997 and 2010, with certain exceptions.  The plaintiffs allege that the Utility collected more than $100 million in customer rates from 1997 through 2010 for the purpose of various safety measures and operations projects but instead used the funds for general corporate purposes such as executive compensation and bonuses.  To state their claims, the plaintiffs cited the January 2012 investigative report from the CPUC’s Safety and Enforcement Division (“SED”) that alleged, from 1996 to 2010, the Utility spent less on capital expenditures and operations and maintenance expense for its natural gas transmission operations than it recovered in rates, by $95 million and $39 million, respectively.  The SED recommended that the Utility should use such amounts to fund future gas transmission expenditures and operations.  Plaintiffs allege that PG&E Corporation and the Utility engaged in unfair business practices in violation of Section 17200 of the California Business and Professions Code (“Section 17200”) and claim that this violation also constitutes a violation of California Public Utilities Code Section 2106 (“Section 2106”), which provides a private right of action for violations of the California constitution or state laws by public utilities.  Plaintiffs seek restitution and disgorgement under Section 17200 and compensatory and punitive damages under Section 2106.  PG&E Corporation and the Utility contest the allegations.  In January 2013, PG&E Corporation and the Utility requested that the court dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs’ allegations.  In the alternative, PG&E Corporation and the Utility requested that the court stay the proceeding until the CPUC investigations described above are concluded.  The court has set a hearing on the motion for April 26, 2013. 

For additional information, see the discussion within MD&A under the heading, “Natural Gas Matters” and in Note 15: Commitments and Contingencies of the Notes to the Consolidated Financial Statements contained in the 2012 Annual Report, which discussions are incorporated herein by reference.

Pending CPUC Investigations and Potential Enforcement Matters

The CPUC is conducting three investigations pertaining to the Utility’s natural gas operations that relate to (1) the Utility’s safety recordkeeping for its natural gas transmission system, (2) the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility’s pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the San Bruno accident. In 2012, the SED issued investigative reports in each of these investigations alleging that the Utility committed numerous violations of applicable laws and regulations and recommending the CPUC impose penalties on the Utility.  Evidentiary hearings were held in each of these investigations. The CPUC administrative law judges (“ALJs”) who oversee the investigations have adopted a revised procedural schedule, including the dates by which the parties’ briefs must be submitted.  The ALJs have also permitted the other parties (the City of San Bruno, The Utility Reform Network, and the City and County of San Francisco) to separately address in their opening briefs their allegations against the Utility, if any, in addition to the allegations made by the SED.

The ALJs have ordered the SED and other parties to file single coordinated briefs to address potential monetary penalties and remedies (which could include remedial operational or policy measures) for all three investigations by April 26, 2013.  After briefing has been completed, the ALJs will issue one or more presiding officer’s decisions listing the violations determined to have been committed, the amount of penalties, and any required remedial actions.  Based on the revised procedural schedule, one or more presiding officer’s decisions will be issued by July 23, 2013.  The decisions would become the final decisions of the CPUC thirty days after issuance unless the Utility or another party filed an appeal, or a CPUC commissioner requested review of the decision, within such time.

California gas corporations are required to provide notice to the CPUC of any self-identified or self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and utilities’ natural gas operating practices.  The CPUC has authorized the SED to issue citations and impose penalties based on self-reported violations.  In April 2012, the CPUC affirmed a $17 million penalty that had been imposed by the SED based on the Utility’s self-report that it failed to conduct periodic leak surveys because it had not included 16 gas distribution maps in its leak survey schedule.  (The Utility has paid the penalty and completed all of the missed leak surveys.)  As of December 31, 2012, the Utility has submitted 34 self-reports with the CPUC, plus additional follow-up reports.  The SED has not yet taken formal action with respect to the Utility’s other self-reports.  The SED may issue additional citations and impose penalties on the Utility associated with these or future reports that the Utility may file.

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In addition, in July 2012, the Utility reported to the CPUC that it had discovered that its access to some pipelines has been limited by vegetation overgrowth or building structures that encroach upon some of the Utility’s gas transmission pipeline rights-of-way.  The Utility is undertaking a system-wide effort to identify and remove encroachments from its pipeline rights-of-way over a multi-year period.  PG&E Corporation and the Utility are uncertain how this matter will affect the investigative proceedings related to natural gas operations, or whether additional proceedings or investigations will be commenced by the CPUC that could result in regulatory orders or the imposition of penalties on the Utility.

The CPUC can impose significant penalties for violations of applicable laws, rules, and orders.  The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged.   The CPUC has historically exercised this discretion in determining penalties.The CPUC's delegation of enforcement authority to the SED allows the SED to use these factors in exercising discretion to determine the number of violations, but the SED is required to impose the maximum statutory penalty for each separate violation that the SED finds.

For more information, see discussions within MD&A under the heading, “Natural Gas Matters,” and Note 15: Commitments and Contingencies−Legal and Regulatory Contingencies, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which discussions are incorporated herein by reference

Criminal Investigation

On June 9, 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident.  These representatives have indicated that the Utility is a target of the investigation.  The Utility is cooperating with the investigation.  PG&E Corporation and the Utility are uncertain whether any criminal charges will be brought against either company or any of their current or former employees.  PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Utility. See the discussions within MD&A under the heading “Natural Gas Matters – Criminal Investigation,” and in Note 15: Commitments and Contingencies of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which discussions are incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable.

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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, 2013 were as follows.

Name	Age	Position
Anthony F. Earley, Jr.	63	Chairman of the Board, Chief Executive Officer, and President
Kent M. Harvey	54	Senior Vice President and Chief Financial Officer
Christopher P. Johns	52	President, Pacific Gas and Electric Company
Hyun Park	51	Senior Vice President and General Counsel
Greg S. Pruett	55	Senior Vice President, Corporate Affairs
John R. Simon	48	Senior Vice President, Human Resources

All officers of PG&E Corporation serve at the pleasure of the Board of Directors of PG&E Corporation.  During at least the past five years through February 1, 2013, 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
Anthony F. Earley, Jr.	Chairman of the Board, Chief Executive Officer, and President	September 13, 2011 to present
	Executive Chairman of the Board, DTE Energy Company	October 1, 2010 to September 12, 2011
	Chairman of the Board and Chief Executive Officer, DTE Energy Company	August 1998 to September 30, 2010

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
	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
Hyun Park	Senior Vice President and General Counsel	November 13, 2006 to present
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
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

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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, 2013 were as follows:

Name		Age	Position
	Anthony F. Earley, Jr.	63	Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation
	Christopher P. Johns	52	President
	Nickolas Stavropoulos	54	Executive Vice President, Gas Operations
	Geisha J. Williams	51	Executive Vice President, Electric Operations
	Karen A. Austin	51	Senior Vice President and Chief Information Officer
	Desmond A. Bell	50	Senior Vice President, Safety and Shared Services
	Thomas E. Bottorff	59	Senior Vice President, Regulatory Affairs
	Helen A. Burt	56	Senior Vice President and Chief Customer Officer
	John T. Conway	55	Senior Vice President, Energy Supply
	Edward D. Halpin	51	Senior Vice President and Chief Nuclear Officer
	Kent M. Harvey	54	Senior Vice President, Financial Services
	Gregory K. Kiraly	48	Senior Vice President, Electric Distribution Operations
	Hyun Park	51	Senior Vice President and General Counsel, PG&E Corporation
	Greg S. Pruett	55	Senior Vice President, Corporate Affairs
	John R. Simon	48	Senior Vice President, Human Resources
	Jesus Soto, Jr.	45	Senior Vice President, Gas Transmission Operations
	Fong Wan	51	Senior Vice President, Energy Procurement
	Dinyar B. Mistry	50	Vice President, Chief Financial Officer, and Controller

All officers of the Utility serve at the pleasure of the Board of Directors of the Utility.  During at least the past five years through February 1, 2013, 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.

Name	Position		Period Held Office
Anthony F. Earley, Jr.	Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation		September 13, 2011 to present
	Executive Chairman of the Board, DTE Energy Company		October 1, 2010 to September 12, 2011
		Chairman of the Board and Chief Executive Officer, DTE Energy Company	August 1998 to September 30, 2010
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
Nickolas Stavropoulos	Executive Vice President, Gas Operations		June 13, 2011 to present
	Executive Vice President and Chief Operating Officer, U.S. Gas Distribution, National Grid		August 2007 to March 31, 2011
Geisha J. Williams	Executive Vice President, Electric Operations		June 1, 2011 to present
	Senior Vice President, Energy Delivery		December 1, 2007 to May 31, 2011
Karen A. Austin	Senior Vice President and Chief Information Officer		June 1, 2011 to present
	President, Consumer Electronics, Sears Holdings		February 2009 to May 2011
	Executive Vice President, Chief Information Officer, Sears Holdings		March 2005 to January 2009
Desmond A. Bell	Senior Vice President, Safety and Shared Services		January 1, 2012 to present
	Senior Vice President, Shared Services and Chief Procurement Officer		October 1, 2008 to December 31, 2011
	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
Thomas E. Bottorff	Senior Vice President, Regulatory Affairs		September 1, 2012 to present
	Senior Vice President, Regulatory Relations		October 14, 2005 to August 31, 2012

33

Helen A. Burt	Senior Vice President and Chief Customer Officer	February 27, 2006 to present
John T. Conway	Senior Vice President, Energy Supply	March 1, 2012 to present
	Senior Vice President, Energy Supply and Chief Nuclear Officer	April 1, 2009 to February 29, 2012
	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
Edward D. Halpin	Senior Vice President and Chief Nuclear Officer	April 2, 2012 to present
	President, Chief Executive Officer and Chief Nuclear Officer, South Texas Project Nuclear Operating Company	December 2009 to March 2012
	Chief Nuclear Officer, South Texas Project Nuclear Operating Company	October 2008 to November 2009
	Site Vice President, South Texas Project Nuclear Operating Company	June 2006 to September 2008
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
Gregory K. Kiraly	Senior Vice President, Electric Distribution Operations	September 18, 2012 to present
	Vice President, Electric Distribution Operations	October 1, 2011 to September 17, 2012
	Vice President, SmartMeter Operations	August 23, 2010 to September 30, 2011
	Vice President, Electric Maintenance and Construction	January 1, 2010 to August 22, 2010
	Vice President, Transmission Substations, Maintenance and Construction	January 1, 2009 to December 31, 2009
	Vice President, Maintenance and Construction	April 14, 2008 to December 31, 2008
	Vice President, Distribution Systems Operations, Energy Delivery, Commonwealth Edison Company	June 2007 to April 2008
Hyun Park	Senior Vice President and General Counsel, PG&E Corporation	November 13, 2006 to present
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
	Senior Vice President, Corporate Relations, PG&E Corporation	November 1, 2007 to October 31, 2009
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
Jesus Soto, Jr.	Senior Vice President, Gas Transmission Operations	May 29, 2012 to present
	Vice President, Operations Services, El Paso Pipeline Group	May 2007 to May 2012
Fong Wan	Senior Vice President, Energy Procurement	October 1, 2008 to present
	Vice President, Energy Procurement	January 9, 2006 to September 30, 2008
Dinyar B. Mistry	Vice President, Chief Financial Officer, and Controller	October 1, 2011 to present
	Vice President and Controller, PG&E Corporation	March 8, 2010 to present
	Vice President and Controller	March 8, 2010 to September 30, 2011
	Vice President and Chief Risk and Audit Officer	September 16, 2009 to March 7, 2010
	Vice President and Chief Risk and Audit Officer, PG&E Corporation	August 1, 2009 to March 7, 2010
	Vice President, Internal Auditing/Compliance and Ethics, PG&E Corporation	January 1, 2009 to July 31, 2009
	Vice President, Regulation and Rates	September 20, 2007 to December 31, 2008

34

PART II

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

As of February 11, 2013, there were 67,982 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 exchange.  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 2012 Annual Report, which information is incorporated herein by reference.  Shares of common stock of the Utility are solely owned by PG&E Corporation.  Information about the frequency, amount, and restrictions upon the payment 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, Note 6: Common Stock and Share-Based Compensation−Dividends of the Notes to the Consolidated Financial Statements, and within MD&A under the heading “Liquidity and Financial Resources—Dividends,” in the 2012 Annual Report, which information is incorporated herein by reference.

Sales of Unregistered Equity Securities

During the quarter ended December 31, 2012, PG&E Corporation made equity contributions totaling $170 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 2012.

Issuer Purchases of Equity Securities

PG&E Corporation common stock:

Period	Total Number of Shares Purchased	Average Price Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
October 1 through October 31, 2012	-	-	-	$ -
November 1 through November 30, 2012	-	-	-	-
December 1 through December 31, 2012	406(1)	$39.71	-	-
Total	406	$39.71	-	$ -
(1) Shares of PG&E Corporation common stock tendered to pay stock option exercise price.

                During the quarter ended December 31, 2012, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

Item 6. Selected Financial Data

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 2012 Annual Report, which information is incorporated herein by reference.

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 2012 Annual Report, which discussion is incorporated herein by reference.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Information responding to Item 7A is set forth within MD&A under the heading “Risk Management Activities,” and in Note 10: Derivatives and Note 11: Fair Value Measurements of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.

Item 8. Financial Statements and Supplementary Data

Information responding to Item 8 is set forth under the following headings for PG&E Corporation: “Consolidated Statements of Income,” “Consolidated Statements of Comprehensive 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 Statements of Comprehensive Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders' Equity” in the 2012 Annual Report 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” in the 2012 Annual Report, which information is incorporated herein by reference.

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, 2012, 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, 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, 2012 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 2012 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

2013 PG&E Corporation Short-Term Incentive Plan

On February 20, 2013, the Compensation Committee of the PG&E Corporation Board of Directors (“Committee”) approved the PG&E Corporation 2013 Short-Term Incentive Plan (“STIP”) under which officers and employees of PG&E Corporation and the Utility may receive cash awards based on the extent to which specified performance targets are met in each of three areas: safety (both public and employee), customer (which includes operational reliability and the efficient completion of pipeline safety work), and corporate financial performance.  The resulting STIP scores for each of these measures will have the following weightings: safety (40%), customer (35%), and corporate financial performance (25%).  The Committee also approved the specific performance targets for each of these STIP components.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information regarding executive officers of PG&E Corporation and the Utility is set forth under “Executive Officers of the Registrants” at the end of Part I of this report.  Other information regarding directors is set forth under the heading “Nominees for Directors of PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2013 Annual Meetings of Shareholders, which information is incorporated herein 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 2013 Annual Meetings of Shareholders, which information is incorporated herein by reference.

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 2012 there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2013 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 set forth under the headings “Corporate Governance  Board Committee Duties and Composition  Audit Committees” and “Corporate Governance  Board and Director Independence  Committee Membership Requirements” and “Corporate Governance – Committee Membership” in the Joint Proxy Statement relating to the 2013 Annual Meetings of Shareholders, which information is incorporated herein by reference.

Item 11. Executive Compensation

Information responding to Item 11, for each of PG&E Corporation and the Utility, is set forth under the headings “Compensation Discussion and Analysis,” “Compensation Committee Report,”  “Summary Compensation Table - 2012,” “Grants of Plan-Based Awards in 2012,” “Outstanding Equity Awards at Fiscal Year End - 2012,” “Option Exercises and Stock Vested During 2012,” “Pension Benefits – 2012,” “Non-Qualified Deferred Compensation – 2012,”  “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” and “Compensation of Non-Employee Directors – 2012 Director Compensation” in the Joint Proxy Statement relating to the 2013 Annual Meetings of Shareholders, which information is hereby incorporated herein 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 set forth under the headings “Security Ownership of Management” and “Share Ownership Information - Principal Shareholders” in the Joint Proxy Statement relating to the 2013 Annual Meetings of Shareholders, which information is incorporated herein by reference.

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Equity Compensation Plan Information

The following table provides information as of December 31, 2012 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		5,758,820	(1)	$	30.05		4,548,119	(2)
Equity compensation plans not  approved by shareholders		-			-		-
Total equity compensation plans		5,758,820	(1)	$	30.05		4,548,119	(2)

  (1) Includes 45,597 phantom stock units, 2,101,484 restricted stock units and 3,088,896 performance shares.  The weighted average exercise price reported in column (b) does not take these awards into account.  For a description of these performance shares, see Note 6: Common Stock and Share-Based Compensation of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which description is incorporated herein by reference.  For performance shares, amounts reflected in this table assume payout in shares at 200% of target.  The actual number of shares issued can range from 0% to 200% of target depending on achievement of total shareholder return objectives.  Also, restricted stock units and performance shares are generally settled in net shares.  Upon vesting, shares with a value equal to required tax withholding will be withheld and, in lieu of issuing the shares, taxes will be paid on behalf of employees.  Shares not issued due to share withholding or performance achievement below maximum will be available again for issuance.

  (2)  Represents the total number of shares available for issuance under the PG&E Corporation Long-Term Incentive Program (“LTIP”) and the PG&E Corporation 2006 Long-Term Incentive Plan (“2006 LTIP”) as of December 31, 2012.  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 2006 LTIP, see Note 6: Common Stock and Share-Based Compensation of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which description is incorporated herein by reference.

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 Party Transactions and “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company –Board and Director Independence” in the Joint Proxy Statement relating to the 2013 Annual Meetings of Shareholders, which information is incorporated herein by reference.

Item 14. Principal Accountant Fees and Services

Information responding to Item 14, for each of PG&E Corporation and the Utility, is set forth 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 2013 Annual Meetings of Shareholders, which information is incorporated herein 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 2012 Annual Report and are incorporated by reference in this report:

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Consolidated Statements of Income for the Years Ended December 31, 2012, 2011, and 2010 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2012, 2011, and 2010 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Balance Sheets at December 31, 2012 and 2011 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011, and 2010 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Equity for the Years Ended December 31, 2012, 2011, and 2010 for PG&E Corporation.

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2012, 2011, and 2010 for Pacific Gas and Electric Company.

Notes to the Consolidated Financial Statements.

Quarterly Consolidated Financial Data (Unaudited).

Reports 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, 2012 and 2011 and for the Years Ended December 31, 2012, 2011, and 2010.

II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2012, 2011, and 2010.

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)

39

Exhibit Number	Exhibit Description
3.3	Bylaws of PG&E Corporation amended as of March 1, 2012 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2012 (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 June 20, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 3)
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	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)
4.9	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)
4.10	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)
4.11	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)

40

Exhibit Number	Exhibit Description
4.12	Thirteenth Supplemental Indenture dated as of May 13, 2011, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021.  (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348), Exhibit 4.1)
4.13	Fourteenth Supplemental Indenture dated as of September 12, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company's 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1)
4.14	Fifteenth Supplemental Indenture dated as of November 22, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 20, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 22, 2011 (File No. 1-2348), Exhibit 4.1)
4.15	Sixteenth Supplemental Indenture dated as of December 1, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1)
4.16	Seventeenth Supplemental Indenture dated as of April 16, 2012 relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.45% Senior Notes due April 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.17	Eighteenth Supplemental Indenture dated as of August 16, 2012 relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.45% Senior Notes due August 15, 2022 and $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due August 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.18	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)
4.19	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 May 31, 2011, among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A. as administrative agent and a lender, (3) Citibank, N.A., and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.1)
10.2	Amendment No. 1, dated as of December 24, 2012, to the May 31, 2011 Credit Agreement among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A. as administrative agent and a lender, (3) Citibank, N.A., and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank

41

Exhibit Number	Exhibit Description
10.3	Credit Agreement, dated May 31, 2011, among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank, N.A., as administrative agent and lender, (3) JPMorgan Chase Bank, N.A., and Bank of America, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.2)
10.4	Amendment No. 1, dated as of December 24, 2012, to the May 31, 2011 Credit Agreement among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank, N.A., as administrative agent and lender, (3) JPMorgan Chase Bank, N.A., and Bank of America, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank
10.5	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)
10.6	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)
10.7	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)
10.8*	Restricted Stock Unit Agreement between C. Lee Cox and PG&E Corporation dated May 12, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.3)
10.9*	Letter regarding Compensation Agreement between PG&E Corporation and Anthony F. Earley, Jr. dated August 8, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.1)
10.10*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant 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, 2012 (File No. 1-12609), Exhibit 10.3)
10.11*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.2)
10.12*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.3)
10.13*	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant 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, 2012 (File No. 1-12609), Exhibit 10.4)
10.14*	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.4)

42

Exhibit Number	Exhibit Description
10.15*	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.5)
10.16*	Restricted Stock Unit Agreement between Christopher P. Johns and PG&E Corporation dated May 9, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.4)
10.17*	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)
10.18*	Letter regarding Compensation Arrangement between PG&E Corporation and John R. Simon dated March 9, 2007
10.19*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Jesus Soto, Jr. dated April 4, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.2)
10.20*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Edward D. Halpin dated February 3, 2012 for employment starting April 1, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.21)
10.21*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Karen Austin dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.7)
10.22*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Nick Stavropoulos dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.8)
10.23*	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)
10.24*	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 and as of August 1, 2011) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.11)
10.25*	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)
10.26*	PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)
10.27*	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2013
10.28*	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2012 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2012 (File No. 1-12609), Exhibit 10.31)
10.29*	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)

43

Exhibit Number	Exhibit Description
10.30*	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)
10.31*	PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of January 1, 2013
10.32*	PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, effective January 1, 2013
10.33*	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)
10.34*	Postretirement Life Insurance Plan of the Pacific Gas and Electric Company as amended and restated on February 14, 2012 (incorporated by reference to Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-2348), Exhibit 10.7)
10.35 *	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)
10.36*	Resolution of the PG&E Corporation Board of Directors dated September 19, 2012, adopting director compensation arrangement effective January 1, 2013
10.37*	Resolution of the Pacific Gas and Electric Company Board of Directors dated September 19, 2012, adopting director compensation arrangement effective January 1, 2013
10.38*	Resolution of the PG&E Corporation Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.31)
10.39*	Resolution of the Pacific Gas and Electric Company Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2010 (File No. 1-12348), Exhibit 10.32)
10.40*	PG&E Corporation 2006 Long-Term Incentive Plan, as amended effective January 1, 2013
10.41 *	PG&E Corporation 2006 Long-Term Incentive Plan, as amended effective June 15, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.10)
10.42*	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)
10.43*	Form of Restricted Stock Agreement for 2012 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, 2012 (File No. 1-12609), Exhibit 10.1)
10.44*	Form of Restricted Stock Unit Agreement for 2011 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, 2011 (File No. 1-12609), Exhibit 10.1)
10.45*	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)
10.46*	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)
10.47*	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)

44

Exhibit Number	Exhibit Description
10.48*	Form of Amendment to Restricted Stock Agreements for grants made between January 2005 and March 2008 (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)
10.49*	Form of Restricted Stock Unit Agreement for 2012 grants to directors 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 June 30, 2012 (File No. 1-12609), Exhibit 10.3)
10.50*	Form of Restricted Stock Unit Agreement for 2011 grants to directors 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 June 30, 2011 (File No. 1-12609), Exhibit 10.9)
10.51*	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. 1-12609 and File No. 1-2348), Exhibit 99.1)
10.52*	Form of Performance Share Agreement for 2012 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, 2012 (File No. 1-12609), Exhibit 10.2)
10.53*	Form of Performance Share Agreement for 2011 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, 2011 (File No. 1-12609), Exhibit 10.2)
10.54*	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)
10.55*	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)
10.56*	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)
10.57*	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)
10.58*	PG&E Corporation 2012 Officer Severance Policy, effective as of March 1, 2012 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.6)
10.59*	PG&E Corporation Officer Severance Policy, as amended effective as of March 1, 2012(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.5)
10.60*	PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.51)
10.61*	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)
10.62*	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)
10.63*	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)
10.64*	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)

45

Exhibit Number	Exhibit Description
10.65*	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)
10.66 *	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)
10.67*	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 2012 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 Statements of Comprehensive 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 Statements of Comprehensive 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	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.LAB	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition 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.

46

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, 2012 to be signed on their behalf by the undersigned, thereunto duly authorized.

	PG&E CORPORATION		PACIFIC GAS AND ELECTRIC COMPANY
	(Registrant) ANTHONY F. EARLEY, JR.		(Registrant) CHRISTOPHER P. JOHNS
	Anthony F. Earley, Jr.		Christopher P. Johns
By:	Chairman of the Board, Chief Executive Officer, and President	By:	President
Date:	February 21, 2013	Date:	February 21, 2013

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
	Chairman of the Board, Chief Executive Officer, and President (PG&E Corporation)
ANTHONY F. EARLEY, JR.		February 21, 2013
Anthony F. Earley, Jr.
CHRISTOPHER P. JOHNS	President (Pacific Gas and Electric Company)		February 21, 2013
Christopher P. Johns
B.  Principal Financial Officers
KENT M. HARVEY	Senior Vice President and Chief Financial Officer (PG&E Corporation)		February 21, 2013
Kent M. Harvey
DINYAR B. MISTRY	Vice President, Chief Financial Officer, and Controller (Pacific Gas and Electric Company)		February 21, 2013
Dinyar B. Mistry
C. Principal Accounting Officer
DINYAR B. MISTRY	Vice President and Controller (PG&E Corporation) Vice President, Chief Financial Officer, and Controller (Pacific Gas and Electric Company)		February 21, 2013
Dinyar B. Mistry
D.  Directors
	Director		February 21, 2013
David R. Andrews
*LEWIS CHEW	Director		February 21, 2013
Lewis Chew
*C. LEE COX	Director		February 21, 2013
C. Lee Cox

47

*ANTHONY F. EARLEY, JR.		Director	February 21, 2013
Anthony F. Earley, Jr.
*FRED J. FOWLER		Director	February 21, 2013
Fred J. Fowler
*MARYELLEN C. HERRINGER		Director	February 21, 2013
Maryellen C. Herringer
*CHRISTOPHER P. JOHNS		Director (Pacific Gas and Electric Company only)	February 21, 2013
Christopher P. Johns
*ROGER H. KIMMEL		Director	February 21, 2013
Roger H. Kimmel
*RICHARD A. MESERVE		Director	February 21, 2013
Richard A. Meserve
*FORREST E. MILLER		Director	February 21, 2013
Forrest E. Miller
*ROSENDO G. PARRA		Director	February 21, 2013
Rosendo G. Parra
*BARBARA L. RAMBO		Director	February 21, 2013
Barbara L. Rambo
*BARRY LAWSON WILLIAMS		Director	February 21, 2013
Barry Lawson Williams
*By:	HYUN PARK
	HYUN PARK, Attorney-in-Fact

48

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, 2012 and 2011, and for each of the three years in the period ended December 31, 2012, and the Company's and the Utility’s internal control over financial reporting as of December 31, 2012, and have issued our reports thereon dated February 21, 2013 (which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph relating to several investigations and enforcement matters pending with the California Public Utilities Commission that may result in material amounts of penalties); such consolidated financial statements and reports are included in your 2012 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. 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.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 21, 2013

49

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

 (in millions, except per share amounts)

	Year Ended December 31,
	2012			2011			2010
Administrative service revenue	$	43		$	44		$	53
Operating expenses		(41	)		(44	)		(55	)
Interest income		1			1			1
Interest expense		(22	)		(22	)		(35	)
Other income (expense)		(39	)		(17	)		4
Equity in earnings of subsidiaries		817			852			1,105
Income before income taxes		759			814			1,073
Income tax benefit		57			30			26
Net income	$	816		$	844		$	1,099
Other Comprehensive Income
Pension and other postretirement benefit plans (net of income tax of $72, $9, $25 in 2012, 2011, and 2010, respectively)		108			(11	)		(42	)
Other (net of income tax of $3 in 2012)		4			-			-
Total other comprehensive income (loss)		112			(11	)		(42	)
Comprehensive Income	$	928		$	833		$	1,057
Weighted average common shares outstanding, basic		424			401			382
Weighted average common shares outstanding, diluted		425			402			392
Net earnings per common share, basic	$	1.92		$	2.10		$	2.86
Net earnings per common share, diluted	$	1.92		$	2.10		$	2.82

                PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS.  In addition, during 2010, PG&E Corporation applied the “if-converted” method to reflect the impact of the Convertible Subordinated Notes to the extent it was dilutive when compared to basic EPS.

50

PG&E CORPORATION

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

CONDENSED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2012			2011
ASSETS
Current Assets
Cash and cash equivalents	$	207		$	209
Advances to affiliates		26			18
Income taxes receivable		33			8
Deferred income taxes		-			4
Total current assets		266			239
Noncurrent Assets
Equipment		1			14
Accumulated depreciation		(1	)		(14	)
Net equipment		-			-
Investments in subsidiaries		13,387			12,378
Other investments		102			94
Income taxes receivable		5			2
Deferred income taxes		178			143
Other		1			2
Total noncurrent assets		13,673			12,619
Total Assets	$	13,939		$	12,858
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	120		$	-
Accounts payable – other		48			21
Income taxes payable		-			57
Other		221			208
Total current liabilities		389			286
Noncurrent Liabilities
Long-term debt		349			349
Other		127			122
Total noncurrent liabilities		476			471
Common Shareholders’ Equity
Common stock		8,428			7,602
Reinvested earnings		4,747			4,712
Accumulated other comprehensive loss		(101	)		(213	)
Total common shareholders’ equity		13,074			12,101
Total Liabilities and Shareholders’ Equity	$	13,939		$	12,858

51

PG&E CORPORATION

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

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2012			2011			2010
Cash Flows from Operating Activities:
Net income	$	816		$	844		$	1,099
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization		51			36			38
Equity in earnings of subsidiaries		(817	)		(852	)		(1,105	)
Deferred income taxes and tax credits, net		(31	)		(26	)		19
Noncurrent income taxes receivable/payable		(6	)		(47	)		34
Current income taxes receivable/payable		(82	)		49			(1	)
Other		20			(80	)		(50	)
Net cash provided by (used in) operating activities		(49	)		(76	)		34
Cash Flows From Investing Activities:
Investment in subsidiaries		(1,023	)		(759	)		(347	)
Dividends received from subsidiaries (1)		716			716			716
Proceeds from tax equity investments		228			129			7
Other		-			-			(4	)
Net cash provided by (used in) investing activities		(79	)		86			372
Cash Flows From Financing Activities:
Borrowings under revolving credit facilities		120			150			90
Repayments under revolving credit facilities		-			(150	)		(90	)
Common stock issued		751			662			303
Common stock dividends paid (2)		(746	)		(704	)		(662	)
Other		1			1			-
Net cash provided by (used in) financing activities		126			(41	)		(359	)
Net change in cash and cash equivalents		(2	)		(31	)		47
Cash and cash equivalents at January 1		209			240			193
Cash and cash equivalents at December 31	$	207		$	209		$	240
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(20	)	$	(20	)	$	(20	)
Income taxes, net		(60	)		8			36
Supplemental disclosures of noncash investing and financing
activities
Noncash common stock issuances	$	22		$	24		$	265
Common stock dividends declared but not yet paid		196			188			183
(1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow.
(2) On January 15, April 15, July 15, October 15, 2012, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
On January 15, April 15, July 15, October 15, 2011, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
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.

52

PG&E Corporation

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2012, 2011, and 2010

(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:
2012:
Allowance for uncollectible accounts(1)	$	81	$	66	$	-	$	60	$	87
2011:
Allowance for uncollectible accounts(1)	$	81	$	60	$	-	$	60	$	81
2010:
Allowance for uncollectible accounts(1)	$	68	$	56	$	-	$	43	$	81
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable – Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

53

Pacific Gas and Electric Company

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2012, 2011, and 2010

(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:
2012:
Allowance for uncollectible accounts(1)	$	81	$	66	$	-	$	60	$	87
2011:
Allowance for uncollectible accounts(1)	$	81	$	60	$	-	$	60	$	81
2010:
Allowance for uncollectible accounts(1)	$	68	$	56	$	-	$	43	$	81
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable – Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

54

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 March 1, 2012 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2012 (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 June 20, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 3)
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)

Exhibit Number	Exhibit Description
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	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)
4.9	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)
4.10	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)
4.11	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)
4.12	Thirteenth Supplemental Indenture dated as of May 13, 2011, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021.  (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348), Exhibit 4.1)
4.13	Fourteenth Supplemental Indenture dated as of September 12, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company's 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1)
4.14	Fifteenth Supplemental Indenture dated as of November 22, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 20, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 22, 2011 (File No. 1-2348), Exhibit 4.1)
4.15	Sixteenth Supplemental Indenture dated as of December 1, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1)
4.16	Seventeenth Supplemental Indenture dated as of April 16, 2012 relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.45% Senior Notes due April 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.17	Eighteenth Supplemental Indenture dated as of August 16, 2012 relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.45% Senior Notes due August 15, 2022 and $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due August 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.18	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)

Exhibit Number	Exhibit Description
4.19	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 May 31, 2011, among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A. as administrative agent and a lender, (3) Citibank, N.A., and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.1)
10.2	Amendment No. 1, dated as of December 24, 2012, to the May 31, 2011 Credit Agreement among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A. as administrative agent and a lender, (3) Citibank, N.A., and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank
10.3	Credit Agreement, dated May 31, 2011, among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank, N.A., as administrative agent and lender, (3) JPMorgan Chase Bank, N.A., and Bank of America, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.2)
10.4	Amendment No. 1, dated as of December 24, 2012, to the May 31, 2011 Credit Agreement among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank, N.A., as administrative agent and lender, (3) JPMorgan Chase Bank, N.A., and Bank of America, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank
10.5	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)
10.6	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)
10.7	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)
10.8*	Restricted Stock Unit Agreement between C. Lee Cox and PG&E Corporation dated May 12, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.3)

Exhibit Number	Exhibit Description
10.9*	Letter regarding Compensation Agreement between PG&E Corporation and Anthony F. Earley, Jr. dated August 8, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.1)
10.10*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant 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, 2012 (File No. 1-12609), Exhibit 10.3)
10.11*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.2)
10.12*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.3)
10.13*	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant 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, 2012 (File No. 1-12609), Exhibit 10.4)
10.14*	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.4)
10.15*	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.5)
10.16*	Restricted Stock Unit Agreement between Christopher P. Johns and PG&E Corporation dated May 9, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.4)
10.17*	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)
10.18*	Letter regarding Compensation Arrangement between PG&E Corporation and John R. Simon dated March 9, 2007
10.19*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Jesus Soto, Jr. dated April 4, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.2)
10.20*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Edward D. Halpin dated February 3, 2012 for employment starting April 1, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.21)
10.21*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Karen Austin dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.7)
10.22*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Nick Stavropoulos dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.8)
10.23*	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)
10.24*	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 and as of August 1, 2011) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.11)

Exhibit Number	Exhibit Description
10.25*	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)
10.26*	PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)
10.27*	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2013
10.28*	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2012 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2012 (File No. 1-12609), Exhibit 10.31)
10.29*	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)
10.30*	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)
10.31*	PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of January 1, 2013
10.32*	PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, effective January 1, 2013
10.33*	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)
10.34*	Postretirement Life Insurance Plan of the Pacific Gas and Electric Company as amended and restated on February 14, 2012 (incorporated by reference to Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-2348), Exhibit 10.7)
10.35 *	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)
10.36*	Resolution of the PG&E Corporation Board of Directors dated September 19, 2012, adopting director compensation arrangement effective January 1, 2013
10.37*	Resolution of the Pacific Gas and Electric Company Board of Directors dated September 19, 2012, adopting director compensation arrangement effective January 1, 2013
10.38*	Resolution of the PG&E Corporation Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.31)
10.39*	Resolution of the Pacific Gas and Electric Company Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2010 (File No. 1-12348), Exhibit 10.32)
10.40*	PG&E Corporation 2006 Long-Term Incentive Plan, as amended effective January 1, 2013
10.41*	PG&E Corporation 2006 Long-Term Incentive Plan, as amended effective June 15, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.10)
10.42*	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)

Exhibit Number	Exhibit Description
10.43*	Form of Restricted Stock Agreement for 2012 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, 2012 (File No. 1-12609), Exhibit 10.1)
10.44*	Form of Restricted Stock Unit Agreement for 2011 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, 2011 (File No. 1-12609), Exhibit 10.1)
10.45*	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)
10.46*	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)
10.47*	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)
10.48*	Form of Amendment to Restricted Stock Agreements for grants made between January 2005 and March 2008 (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)
10.49*	Form of Restricted Stock Unit Agreement for 2012 grants to directors 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 June 30, 2012 (File No. 1-12609), Exhibit 10.3)
10.50*	Form of Restricted Stock Unit Agreement for 2011 grants to directors 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 June 30, 2011 (File No. 1-12609), Exhibit 10.9)
10.51*	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. 1-12609 and File No. 1-2348), Exhibit 99.1)
10.52*	Form of Performance Share Agreement for 2012 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, 2012 (File No. 1-12609), Exhibit 10.2)
10.53*	Form of Performance Share Agreement for 2011 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, 2011 (File No. 1-12609), Exhibit 10.2)
10.54*	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)
10.55*	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)
10.56*	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)
10.57*	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)
10.58*	PG&E Corporation 2012 Officer Severance Policy, effective as of March 1, 2012 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.6)

Exhibit Number	Exhibit Descrkiption
10.59*	PG&E Corporation Officer Severance Policy, as amended effective as of March 1, 2012(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.5)
10.60*	PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.51)
10.61*	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)
10.62*	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)
10.63*	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)
10.64*	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)
10.65*	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)
10.66 *	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)
10.67*	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 2012 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 Statements of Comprehensive 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 Statements of Comprehensive 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	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.LAB	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition 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.

EX-10.02

Exhibit 10.2

AMENDMENT NO. 1 TO CREDIT AGREEMENT

This AMENDMENT NO. 1 TO CREDIT AGREEMENT (this “Amendment”), dated as of December 24, 2012, is entered into by and among (1) PG&E CORPORATION, a California corporation (the “Borrower”); (2) the Required Lenders (as defined in the Credit Agreement referred to below); and (3) BANK OF AMERICA, N.A., as Administrative Agent, with respect to the following:

A.           The Borrower, the Administrative Agent and the Lenders have previously entered into that certain Credit Agreement dated as of May 31, 2011 (the “Existing Credit Agreement” and as the same may be further amended, restated, supplemented or otherwise modified and in effect from time to time, including, but not limited to, by this Amendment, the “Credit Agreement”).  Capitalized terms are used in this Amendment as defined in the Credit Agreement, unless otherwise defined herein.

B.           The Borrower, the Administrative Agent and the Required Lenders desire to make certain amendments to the Existing Credit Agreement as set forth below on the terms and subject to the conditions set forth in this Amendment.

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

1.Effectiveness.  The effectiveness of the provisions of Section 2 of this Amendment is subject to the satisfaction of the conditions further described in Section 3 of this Amendment.

2.Amendment to Section 8.  On the terms and subject to the conditions of this Amendment, Section 8 of the Existing Credit Agreement is hereby amended by deleting clause (h) in its entirety and replacing it with the following:

“(h)           one or more judgments or decrees shall be entered against the Borrower or any of its Significant Subsidiaries by a court of competent jurisdiction involving in the aggregate a liability (not paid or, subject to customary deductibles, fully covered by insurance as to which the relevant insurance company has not denied coverage) of $100,000,000 or more, and all such judgments or decrees shall not have been vacated, discharged, stayed or bonded pending appeal within 30 days from the entry thereof unless, in the case of a discharge, such judgment or decree is due at a later date in one or more payments and the Borrower or such Subsidiary satisfies the obligation to make such payment or payments on or prior to the date such payment or payments become due in accordance with such judgment or decree; or.”

3.Conditions Precedent to the Effectiveness of this Amendment.  The effectiveness of the provisions of Section 2 of this Amendment is conditioned upon, and such provisions shall not be effective until, satisfaction of the following conditions (the first date on which all of the following conditions have been satisfied being referred to herein as the “Amendment Effective Date”):

1

(a)The Administrative Agent shall have received, on behalf of the Lenders, this Amendment, duly executed and delivered by the Borrower, the Administrative Agent and the Required Lenders.

(b)The representations and warranties set forth in Section 4 of this Amendment shall be true and correct as of the Amendment Effective Date.

(c)No Default or Event of Default shall have occurred and be continuing on the date of the Amendment Effective Date or after giving effect to this Amendment.

4.Representations and Warranties.  In order to induce the Administrative Agent and the Lenders to enter into this Amendment and to amend the Existing Credit Agreement in the manner provided in this Amendment, the Borrower represents and warrants to the Administrative Agent and each Lender that (a) each of the representations and warranties made by the Borrower in the Credit Agreement (i) that does not contain a materiality qualification (other than the representations and warranties set forth in Section 4.2, 4.6(b) and 4.13) shall be true and correct in all material respects on and as of the date of the Amendment Effective Date as if made on and as of such date, and (ii) that contains a materiality qualification (other than the representations and warranties set forth in Sections 4.2, 4.6(b) and 4.13) shall be true and correct on and as of the Amendment Effective Date (or, to the extent such representations and warranties specifically relate to an earlier date, that such representations and warranties were true and correct in all material respects, or true and correct, as the case may be, as of such earlier date); (b) the Borrower has the corporate power and corporate authority to make and deliver this Amendment and to perform the Existing Credit Agreement as amended by this Amendment; (c) the Borrower has taken all necessary corporate action to authorize the execution and delivery of this Amendment and the performance of the Existing Credit Agreement as amended by this Amendment; (d) this Amendment has been duly executed and delivered by the Borrower and constitutes a legal, valid and binding obligation of the Borrower, enforceable against the Borrower in accordance with its terms, except as enforceability may be limited by (x) applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting the enforcement of creditors’ rights generally, laws of general application related to the enforceability of securities secured by real estate and by general equitable principles (whether enforcement is sought by proceedings in equity or at law) and (y) applicable regulatory requirements (including the approval of the CPUC) prior to foreclosure under the Indenture; and (e) the execution and delivery by the Borrower of this Amendment and the performance by the Borrower of this Amendment do not (x) violate in any material respect any Requirement of Law or any Contractual Obligation of the Borrower or any of its Significant Subsidiaries; or (y) result in, or require, the creation or imposition of any Lien on any of their respective properties or revenues pursuant to any Requirement of Law or any such Contractual Obligation (other than the Liens created by the Indenture).   

2

5.Miscellaneous.

(a)Reference to and Effect on the Existing Credit Agreement and the other Loan Documents.

(i)Except as specifically amended by this Amendment, the Existing Credit Agreement and the other Loan Documents shall remain in full force and effect and are hereby ratified and confirmed by the Borrower in all respects.

(ii)The execution and delivery of this Amendment and performance of the Credit Agreement shall not, except as expressly provided herein, constitute a waiver of any provision of, or operate as a waiver of any right, power or remedy of the Administrative Agent or the Lenders under, the Existing Credit Agreement or any of the other Loan Documents.

(iii)Upon the conditions precedent set forth herein being satisfied, this Amendment shall be construed as one with the Existing Credit Agreement, and the Existing Credit Agreement shall, where the context requires, be read and construed throughout so as to incorporate this Amendment.

(iv)If there is any conflict between the terms and provisions of this Amendment and the terms and provisions of the Credit Agreement or any other Loan Document, the terms and provisions of this Amendment shall govern.

(b)Counterparts.  This Amendment may be executed by one or more of the parties to this Amendment on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument.  Delivery of an executed signature page of this Amendment by facsimile transmission (or by email of a PDF or similar electronic image file) shall be effective as delivery of a manually executed counterpart hereof.  A set of the copies of this Amendment signed by all of the parties shall be lodged with the Borrower and the Administrative Agent.

(c)Governing Law.  This Amendment and the rights and obligations of the parties under this Amendment shall be governed by, and construed and interpreted in accordance with, the law of the State of New York.

6.Loan Documents.  This Amendment is a Loan Document as defined in the Credit Agreement, and the provisions of the Credit Agreement generally applicable to Loan Documents are applicable hereto and incorporated herein by this reference.

[This Space Intentionally Left Blank]

3

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the date first above written.

PG&E CORPORATION

By:  NICHOLAS M. BIJUR                            

Name:  Nicholas M. Bijur

Title:  Vice President and Treasurer

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

BANK OF AMERICA, N.A.

as Administrative Agent, an Issuing Lender and as a Lender

By:    PATRICK MARTIN                                  

Name: Patrick Martin

Title: Director

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

CITIBANK, N.A.

as Co-Syndication Agent, an Issuing Lender and as a Lender

By:  MAUREEN P. MARONEY            

Name:  Maureen P. Maroney

Title:  Vice President

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

JPMORGAN CHASE BANK, N.A.,

as Co-Syndication Agent, an Issuing Lender and as a Lender

By:   JUAN JAVELLANA           

Name:  Juan Javellana

Title:  Executive Director

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

THE ROYAL BANK OF SCOTLAND PLC,

as Co-Documentation Agent, an Issuing Lender and as a Lender

By:   EMILY FREEDMAN                     

Name: Emily Freedman

Title:   Vice President

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Co-Documentation Agent, an Issuing Lender and as a Lender

By:  GABRIELA RAMIREZ         

Name:  Gabriela Ramirez

Title:  Assistant Vice President

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

BANCO BILBAO VIZCAYA ARGENTARIA,

S.A. NEW YORK BRANCH,

as a Lender

By:    NIETZSCHE RODRICKS         

Name:  Nietzsche Rodricks

Title:  Executive Director

By:   MICHAEL OKA                            

Name: Michael Oka

Title:  Executive Director

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

THE BANK OF NEW YORK MELLON,

as a Lender

By:     MARK W. ROGERS                 

Name:  Mark W. Rogers

Title:    Vice President

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

Barclays Bank PLC,

as a Lender

By:     MAY HUANG        

Name:  May Huang

Title:  Assistant Vice President

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

BNP PARIBAS,

as a Lender

By:     DENIS O’MEARA                   

Name:  Denis O’Meara

Title:  Managing Director

By:   FRANCIS J. DELANEY                 

Name: Francis J. Delaney

Title:  Managing Director

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

DEUTSCHE BANK AG NEW YORK BRANCH,

as a Lender

By:     MING K. CHU                                  

           Ming K Chu

           Vice President

By:     HEIDI SANDQUIST                           

           Heidi Sandquist

           Director

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

GOLDMAN SACHS BANK USA

as a Lender

By:      MICHELLE LATZONI              

Name:  Michelle Latzoni

Title:    Authorized Signatory

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

MIZUHO CORPORATE BANK, LTD.,

as a Lender

By:     LEON MO                                   

Name:  Leon Mo

Title:    Authorized Signatory

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

Morgan Stanley Bank, N.A.

as a Lender

By:     JOHN DURLAND        

Name:  John Durland

Title:  Authorized Signatory

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

Royal Bank of Canada,

as a Lender

By:      THOMAS CASEY              

Name:  Thomas Casey

Title:  Authorized Signatory

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

UBS LOAN FINANCE LLC

as a Lender

By:      LANA GIFAS                               

Name:  Lana Gifas

Title:    Director

By:     JOSELIN FERNANDES                   

Name: Joselin Fernandes

Title:  Associate Director

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

Union Bank, N.A.

as a Lender

By:      DENNIS BLANK               

Name:  Dennis Blank

Title:    Vice President

[Signature Page to Amendment No. 1 to Credit Agreement – PG&E Corporation]

LOSANGELES 985499 (2K)

EX-10.04

Exhibit 10.4

AMENDMENT NO. 1 TO CREDIT AGREEMENT

This AMENDMENT NO. 1 TO CREDIT AGREEMENT (this “Amendment”), dated as of December 24, 2012, is entered into by and among (1) PACIFIC GAS AND ELECTRIC COMPANY, a California corporation (the “Borrower”); (2) the Required Lenders (as defined in the Credit Agreement referred to below); and (3) CITIBANK, N.A., as Administrative Agent, with respect to the following:

A.           The Borrower, the Administrative Agent and the Lenders have previously entered into that certain Credit Agreement dated as of May 31, 2011 (the “Existing Credit Agreement” and as the same may be further amended, restated, supplemented or otherwise modified and in effect from time to time, including, but not limited to, by this Amendment, the “Credit Agreement”).  Capitalized terms are used in this Amendment as defined in the Credit Agreement, unless otherwise defined herein.

B.           The Borrower, the Administrative Agent and the Required Lenders desire to make certain amendments to the Existing Credit Agreement as set forth below on the terms and subject to the conditions set forth in this Amendment.

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

1.Effectiveness.  The effectiveness of the provisions of Section 2 of this Amendment is subject to the satisfaction of the conditions further described in Section 3 of this Amendment.

2.Amendment to Section 8.  On the terms and subject to the conditions of this Amendment, Section 8 of the Existing Credit Agreement is hereby amended by deleting clause (h) in its entirety and replacing it with the following:

“(h)           one or more judgments or decrees shall be entered against the Borrower or any of its Significant Subsidiaries by a court of competent jurisdiction involving in the aggregate a liability (not paid or, subject to customary deductibles, fully covered by insurance as to which the relevant insurance company has not denied coverage) of $100,000,000 or more, and all such judgments or decrees shall not have been vacated, discharged, stayed or bonded pending appeal within 30 days from the entry thereof unless, in the case of a discharge, such judgment or decree is due at a later date in one or more payments and the Borrower or such Subsidiary satisfies the obligation to make such payment or payments on or prior to the date such payment or payments become due in accordance with such judgment or decree; or.”

3.Conditions Precedent to the Effectiveness of this Amendment.  The effectiveness of the provisions of Section 2 of this Amendment is conditioned upon, and such provisions shall not be effective until, satisfaction of the following conditions (the first date on which all of the following conditions have been satisfied being referred to herein as the “Amendment Effective Date”):

1

(a)The Administrative Agent shall have received, on behalf of the Lenders, this Amendment, duly executed and delivered by the Borrower, the Administrative Agent and the Required Lenders.

(b)The representations and warranties set forth in Section 4 of this Amendment shall be true and correct as of the Amendment Effective Date.

(c)No Default or Event of Default shall have occurred and be continuing on the date of the Amendment Effective Date or after giving effect to this Amendment.

4.Representations and Warranties.  In order to induce the Administrative Agent and the Lenders to enter into this Amendment and to amend the Existing Credit Agreement in the manner provided in this Amendment, the Borrower represents and warrants to the Administrative Agent and each Lender that (a) each of the representations and warranties made by the Borrower in the Credit Agreement (i) that does not contain a materiality qualification (other than the representations and warranties set forth in Section 4.2, 4.6(b) and 4.13) shall be true and correct in all material respects on and as of the date of the Amendment Effective Date as if made on and as of such date, and (ii) that contains a materiality qualification (other than the representations and warranties set forth in Sections 4.2, 4.6(b) and 4.13) shall be true and correct on and as of the Amendment Effective Date (or, to the extent such representations and warranties specifically relate to an earlier date, that such representations and warranties were true and correct in all material respects, or true and correct, as the case may be, as of such earlier date); (b) the Borrower has the corporate power and corporate authority to make and deliver this Amendment and to perform the Existing Credit Agreement as amended by this Amendment; (c) the Borrower has taken all necessary corporate action to authorize the execution and delivery of this Amendment and the performance of the Existing Credit Agreement as amended by this Amendment; (d) this Amendment has been duly executed and delivered by the Borrower and constitutes a legal, valid and binding obligation of the Borrower, enforceable against the Borrower in accordance with its terms, except as enforceability may be limited by (x) applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting the enforcement of creditors’ rights generally, laws of general application related to the enforceability of securities secured by real estate and by general equitable principles (whether enforcement is sought by proceedings in equity or at law) and (y) applicable regulatory requirements (including the approval of the CPUC) prior to foreclosure under the Indenture; and (e) the execution and delivery by the Borrower of this Amendment and the performance by the Borrower of this Amendment do not (x) violate in any material respect any Requirement of Law or any Contractual Obligation of the Borrower or any of its Significant Subsidiaries; or (y) result in, or require, the creation or imposition of any Lien on any of their respective properties or revenues pursuant to any Requirement of Law or any such Contractual Obligation (other than the Liens created by the Indenture).   

LOSANGELES 985498 (2K)

2

5.Miscellaneous.

(a)Reference to and Effect on the Existing Credit Agreement and the other Loan Documents.

(i)Except as specifically amended by this Amendment, the Existing Credit Agreement and the other Loan Documents shall remain in full force and effect and are hereby ratified and confirmed by the Borrower in all respects.

(ii)The execution and delivery of this Amendment and performance of the Credit Agreement shall not, except as expressly provided herein, constitute a waiver of any provision of, or operate as a waiver of any right, power or remedy of the Administrative Agent or the Lenders under, the Existing Credit Agreement or any of the other Loan Documents.

(iii)Upon the conditions precedent set forth herein being satisfied, this Amendment shall be construed as one with the Existing Credit Agreement, and the Existing Credit Agreement shall, where the context requires, be read and construed throughout so as to incorporate this Amendment.

(iv)If there is any conflict between the terms and provisions of this Amendment and the terms and provisions of the Credit Agreement or any other Loan Document, the terms and provisions of this Amendment shall govern.

(b)Counterparts.  This Amendment may be executed by one or more of the parties to this Amendment on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument.  Delivery of an executed signature page of this Amendment by facsimile transmission (or by email of a PDF or similar electronic image file) shall be effective as delivery of a manually executed counterpart hereof.  A set of the copies of this Amendment signed by all of the parties shall be lodged with the Borrower and the Administrative Agent.

(c)Governing Law.  This Amendment and the rights and obligations of the parties under this Amendment shall be governed by, and construed and interpreted in accordance with, the law of the State of New York.

6.Loan Documents.  This Amendment is a Loan Document as defined in the Credit Agreement, and the provisions of the Credit Agreement generally applicable to Loan Documents are applicable hereto and incorporated herein by this reference.

[This Space Intentionally Left Blank]

LOSANGELES 985498 (2K)

3

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the date first above written.

PACIFIC GAS AND ELECTRIC COMPANY

By:  NICHOLAS M. BIJUR                            

Name:  Nicholas M. Bijur

Title:  Vice President and Treasurer

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

CITIBANK, N.A.

as Administrative Agent, an Issuing Lender and as a Lender

By:  MAUREEN P. MARONEY            

Name:  Maureen P. Maroney

Title:  Vice President

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

BANK OF AMERICA, N.A.

as Administrative Agent, an Issuing Lender and as a Lender

By:    PATRICK MARTIN                                  

Name: Patrick Martin

Title: Director

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

JPMORGAN CHASE BANK, N.A.,

as Co-Syndication Agent, an Issuing Lender and as a Lender

By:   JUAN JAVELLANA           

Name:  Juan Javellana

Title:  Executive Director

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

THE ROYAL BANK OF SCOTLAND PLC,

as Co-Documentation Agent, an Issuing Lender and as a Lender

By:   EMILY FREEDMAN                     

Name: Emily Freedman

Title:   Vice President

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

BANCO BILBAO VIZCAYA ARGENTARIA,

S.A. NEW YORK BRANCH,

as a Lender

By:    NIETZSCHE RODRICKS         

Name:  Nietzsche Rodricks

Title:  Executive Director

By:   EDUARDO CUTRIM                            

Name: Eduardo Cutrim

Title:  Executive Director

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

THE BANK OF NEW YORK MELLON,

as a Lender

By:     MARK W. ROGERS                 

Name:  Mark W. Rogers

Title:    Vice President

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.,

as a Lender

By:     ALAN REITER                 

Name:  Alan Reiter

Title:    Vice President

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

Barclays Bank PLC,

as a Lender

By:     MAY HUANG        

Name:  May Huang

Title:  Assistant Vice President

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

BNP PARIBAS,

as a Lender

By:     DENIS O’MEARA                   

Name:  Denis O’Meara

Title:  Managing Director

By:   FRANCIS J. DELANEY                 

Name: Francis J. Delaney

Title:  Managing Director

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

DEUTSCHE BANK AG NEW YORK BRANCH,

as a Lender

By:     MING K. CHU                                  

Ming K Chu

Vice President

By:     HEIDI SANDQUIST                           

Heidi Sandquist

Director

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

GOLDMAN SACHS BANK USA,

as a Lender

By:      MICHELLE LATZONI              

Name:  Michelle Latzoni

Title:    Authorized Signatory

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

MIZUHO CORPORATE BANK, LTD.,

as a Lender

By:     LEON MO                                   

Name:  Leon Mo

Title:    Authorized Signatory

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

Morgan Stanley Bank, N.A.,

as a Lender

By:     JOHN DURLAND        

Name:  John Durland

Title:  Authorized Signatory

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

Royal Bank of Canada,

as a Lender

By:      THOMAS CASEY              

Name:  Thomas Casey

Title:  Authorized Signatory

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

UBS LOAN FINANCE LLC,

as a Lender

By:      LANA GIFAS                               

Name:  Lana Gifas

Title:    Director

By:     JOSELIN FERNANDES                   

Name: Joselin Fernandes

Title:  Associate Director

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

Union Bank, N.A.

as a Lender

By:      DENNIS BLANK               

Name:  Dennis Blank

Title:    Vice President

[Signature Page to Amendment No. 1 to Credit Agreement – Pacific Gas and Electric Company]

LOSANGELES 985498 (2K)

EX-10.18

		Exhibit 10.18
	Peter A. Darbee Chairman of the Board Chief Executive Officer and President	1 Market, Spear Tower Suite 2400 San Francisco CA  94105 415.267.7118 Fax:  415.267.7252

March 9, 2007

Mr. John Simon

5403 South Chester Court

Greenwood Village, CO  80111

Dear Hyun:

On behalf of PG&E Corporation, I am pleased to extend an invitation to you to join our organization as Senior Vice President, Human Resources, reporting to me.

Your initial total compensation package will consist of the following:

1. An annual base salary of $325,000 ($27,083.33/month) subject to possible increases through our annual salary review plan.

2. A one-time bonus of $100,000 payable within 60 days of your date of hire, subject to normal tax withholdings.  Should you leave the company or should your employment be terminated for cause within two years of your date of hire, a prorated amount of this bonus must be refunded to the company.

3. A target incentive of $162,500 (50% of your base salary) in an annual short-term incentive plan under which your actual incentive dollars may range from zero to $325,000 based on performance relative to established goals.  This incentive will be prorated for the number of months worked from your date of hire and will be payable in 2008.

4. Participation in the PG&E Corporation Long-Term Incentive Plan (LTIP) as a band 3 officer.  Grants under the LTIP are currently split equally between restricted stock and performance shares, and are generally made annually on the first business day of the year.  Your initial LTIP grant will be made on your date of hire, and will have an estimated value of $300,000.  This estimated value is used only for the purpose of determining the number of shares for your grant, which will be based on the closing price of PG&E Corporation common stock (PCG) on your date of hire.  The ultimate value that you realize from these grants will depend upon your employment status and the performance of PG&E Corporation common stock.

5. A one-time supplement LTIP grant with an estimated current value of $200,000.  This grant will be apportioned and made in the same manner as the grant described in item 5.

6. Participation in the PG&E Corporation Supplemental Executive Retirement Plan (SERP).  The basic benefit payable from the SERP at retirement is a monthly annuity equal to the product of 1.7% x [average of the three highest years’ combination of salary and annual incentive for the last ten years of service] x years of credited service x 1/12 less any amounts paid or payable from the Pacific Gas and Electric Company Retirement Plan (RP).

Mr. Simon

March 9, 2007

Page 2

7. Conditioned upon meeting plan requirements, you will also be eligible for post-retirement life insurance and post-retirement medical benefits upon retirement under the RP.

8. Participation in the PG&E Corporation Retirement Savings Plan (RSP), a 401(k) defined contribution plan.  You will be eligible to contribute as much as 20% of your salary on either a pre-tax or after-tax basis, subject to legal limits.  After your first year of service, we will match contributions you make, up to 3% of your salary, at 75 cents on each dollar contributed for the second and third years of your employment.  Thereafter, we will match contributions up to 6% of your salary at 75 cents on each dollar contributed.

9. Participation in the PG&E Corporation Supplemental Retirement Savings Plan (SRSP), a non-qualified deferred compensation plan.  You may elect to defer payment of some of your compensation on a pre-tax basis.  We will provide you with the full matching contributions that cannot be provided through the RSP due to legal limitations imposed on highly compensated employees.

10. As a result of your officer level (officer band 3), you will become an eligible participant under Executive Stock Ownership Program effective January 1, 2008.  As an ancillary benefit to that program, you will also be eligible to receive financial counseling from The AYCO Company at a subsidized rate to assist you in your understanding of our compensation and benefits programs and how those programs can help you to achieve financial security.

11. Participation in a cafeteria-style benefits program that permits you to select coverage tailored to your personal needs and circumstances.  The benefits you elect will be effective the first of the month following the date of your hire.

12. PG&E Corporation also offers a paid-time off (PTO) program.  You will be eligible for 200 (25 days) per year.  You will accrue PTO at rate of approximately 17 hours per month, provided that you work full-time for the month.  In addition, PG&E Corporation recognizes ten paid company holidays annually and provides three floating holidays immediately upon hire and at the beginning of each year.

13. An annual perquisite allowance of $20,000 to be used in lieu of individual authorizations for cars and memberships in clubs and civic organizations.

14. A comprehensive executive relocation assistance package, including: (1) the reimbursement of closing costs on the sale of your current residence, contingent upon using a PG&E-designated relocation company and purchasing a new residence, (2) the move of your household goods, including 60 days of storage and the movement of the goods out of storage, and (3) a lump sum payment of $10,000 payable within 60 days of your date of employment.  In addition, the package will include financial assistance in the form of a monthly mortgage subsidy of $3,000 (applicable to interest only) for a period of 36 months.  This subsidy is contingent upon the following: (1) your purchase of a principal residence (within 50 miles of your work location) within one year of your date of hire, (2) your satisfying typical mortgage qualification criteria, and (3) use of a company-designated lender.  Should you have any questions regarding the relocation package, please contact Denise Nicco, Director of Relocation at (415) 973-3814.

Mr. Simon

March 9, 2007

Page 3

This offer is contingent upon your passing a comprehensive background verification including a credit check and security clearance assessment, and a standard drug analysis test.  We will also need to verify your eligibility to work in the United States based on applicable immigration laws.  In addition, your election as an officer of PG&E Corporation is subject to approval by the Board of Directors of PG&E Corporation, and elements of your compensation are subject to approval by the Nominating, Compensation, and Governance Committee of the Board of Directors of PG&E Corporation.

I look forward to your joining our team and believe you will make a strong contribution to the achievement of our being the leading utility in the United States.  I would appreciate receiving your written acceptance of this offer as soon as possible.  Please call me at any time if you have questions.

Sincerely,

/s/ PETER A. DARBEE

PETER A. DARBEE

Attachment

This is to confirm my acceptance of PG&E Corporation’s offer as Senior Vice President, Human Resources as outlined above.

JOHN R. SIMON          

(Signature and Date)

EX-10.27

Exhibit 10.27

2013 OFFICER SHORT-TERM INCENTIVE PLAN

On February 20, 2013, the Compensation Committee of the PG&E Corporation Board of Directors (“Committee”) approved the structure of the 2013 Short-Term Incentive Plan (“STIP”), as well as the weighting and the specific performance targets for each component of the 2013 STIP.  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 2013 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.  STIP company performance may range from a score of 0 to 2.0.  The Committee may apply an individual performance modifier from 0 percent to 150 percent to individual officer awards.  The Committee will retain complete discretion to determine and pay all STIP awards to officers and non-officer employees.  This includes discretion to reduce the final score on any and all measures downward to zero.

The Committee approved the 2013 performance targets for each of the three categories set forth in the table below.

The corporate financial performance target, with a weighting of 25%, 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.

2013 STIP Performance Targets

Category	Relative Weight	2013 Target
Safety (includes both Public and Employee metrics) (1)	40.0%	1.000
Customer (includes customer satisfaction and reliability) (2)	35.0%	1.000
Financial (includes Earnings from Operations)	25.0%	1.000

1. Safety includes four subcomponents:  (1) Nuclear Operations Safety, (2) Electric Operations Safety, (3) Gas Operations Safety, and (4) Employee Safety, all of which measure the Utility’s safety performance with respect to each of those areas.  The Committee will retain complete discretion to reduce the final Safety rating downward to zero based on the Companies’ overall safety performance for 2013.  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.

2. Customer includes five subcomponents: (1) the overall satisfaction of customers, as measured through a quarterly survey, (2) the number of third party “dig-ins” (i.e., damage resulting in repair or replacement of underground facility) to the Utility’s gas and electric assets, (3) the average duration of electricity outages experienced by all customers served, as measured by the System Average Interruption Duration Index , (4) how quickly gas asset information is entered into the Utility’s gas mapping system after a gas project is completed, and (5) the Utility’s ability to complete certain committed work for gas operations-related programs efficiently.

EX-10.31

.

.Exhibit 10.31

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

OF

PG&E CORPORATION

(As Amended Effective as of January 1, 2013)

______________________________________________

           This is the controlling and definitive statement of the Supplemental Executive Retirement Plan (“PLAN”)1 for ELIGIBLE EMPLOYEES of PG&E Corporation (“CORPORATION”), Pacific Gas and Electric Company (“COMPANY”) and such other companies, affiliates, subsidiaries, or associations as the BOARD OF DIRECTORS may designate from time to time.  The PLAN is the successor plan to the Supplemental Executive Retirement Plan of the COMPANY.  The PLAN as contained herein was first adopted effective January 1, 2005.

No new participants can become eligible to accrue benefits under the PLAN on or after January 1, 2013, and existing participants in the PLAN as of January 1, 2013 shall cease to accrue further benefits under the Plan as of the date they become participants in Part III of the RETIREMENT PLAN.

                  ARTICLE 1                      

DEFINITIONS

1.01Basic SERP Benefit shall mean the benefit described in Section 2.01.

1.02Board or Board of Directors shall mean the BOARD OF DIRECTORS of the CORPORATION or, when appropriate, any committee of the BOARD which has been delegated the authority to take action with respect to the PLAN.

1.03Company shall mean the Pacific Gas and Electric Company, a California corporation.

1.04Corporation shall mean PG&E Corporation, a California corporation.

1.05Eligible Employee shall mean individuals who are, prior to January 1, 2013 (1) (a) employees of the COMPANY or, with respect to PG&E Corporation, PG&E Corporation Support Services, Inc., and PG&E Corporation Support Services II, Inc. only, (i) prior to April 1, 2007, were employees who transferred to PG&E Corporation, PG&E Corporation Support Services, Inc., or PG&E Corporation Support Services II, Inc. from Pacific Gas and Electric Company; or  (ii) after March 31, 2007, all employees, and (b) officers in Officer Bands I-V, or (2) such other employees of the COMPANY, the CORPORATION, PG&E Corporation Support Services, Inc., PG&E Corporation Support Services II, Inc., or such other companies, affiliates, subsidiaries, or associations, as may be designated by the Chief Executive Officer of the CORPORATION.  ELIGIBLE EMPLOYEES shall not include employees who retired prior to January 1, 2005, or whose employment relationship with any of the PARTICIPATING EMPLOYERS was otherwise terminated prior to January 1, 2005.

1.06STIP Payment shall mean amounts received by an ELIGIBLE EMPLOYEE under the Short-Term Incentive Plan maintained by the CORPORATION prior to the date the ELIGIBLE EMPLOYEE becomes a participant in Part III of the RETIREMENT PLAN.

1.07PART III of the RETIREMENT PLAN shall mean the cash balance benefit available under the RETIREMENT PLAN.

1.08Participating Employer shall mean the COMPANY, the CORPORATION, PG&E Corporation Support Services, Inc., PG&E Corporation Support Services II, Inc., and any other companies, affiliates, subsidiaries or associations designated by the Chief Executive Officer of the CORPORATION.

1.09Plan shall mean the Supplemental Executive Retirement Plan (“SERP”) as set forth herein and as may be amended from time to time.

1.010Plan Administrator shall mean the Employee Benefit Committee or such individual or individuals as that Committee may appoint to handle the day-to-day affairs of the PLAN.

1.10   Retirement Plan shall mean the Pacific Gas and Electric Company Retirement Plan.

1.11  Salary shall mean the base salary received by an ELIGIBLE EMPLOYEE prior to the date the ELIGIBLE EMPLOYEE becomes a participant in Part III of the RETIREMENT PLAN.  SALARY shall not include amounts received by an employee after such employee ceases to be an ELIGIBLE EMPLOYEE. For purposes of calculating benefits under the PLAN, SALARY shall not be reduced to reflect amounts that have been deferred under the PG&E Corporation Supplemental Retirement Savings Plan.

1.12  Service shall mean “credited service” as that term is defined in the RETIREMENT PLAN or, if the Nominating and Compensation Committee of the BOARD OF DIRECTORS has granted an adjusted service date for an ELIGIBLE EMPLOYEE, “credited service” as calculated from such adjusted service date.  In no event, however, shall SERVICE include periods of time after which an officer has ceased to be an ELIGIBLE EMPLOYEE or after the date the ELIGIBLE EMPLOYEE becomes a participant in Part III of the RETIREMENT PLAN.

                      ARTICLE 2                      

SERP BENEFITS

2.01 The BASIC SERP BENEFIT payable from the PLAN shall be a monthly annuity with an annuity start date of the later of (a) the first of the month following the month in which the ELIGIBLE EMPLOYEE has a separation from service (as provided under Code Section 409A and related guidance), or (b) the first of the month following the ELIGIBLE EMPLOYEE’s 55th birthday; provided, however, that no payments under the PLAN shall be made until the seventh month following the annuity start date.  The first payment shall consist of the monthly annuity payment for the seventh month, plus the first six monthly annuity payments, including interest calculated at a rate to reflect the CORPORATION’s marginal cost of funds.  The monthly amount of the BASIC SERP BENEFIT shall be equal to the product of:

1.7%  x  the average of three highest calendar years’ combination of SALARY and STIP PAYMENT for the last ten years of SERVICE  x  SERVICE  x  1/12.

In computing a year’s combination of SALARY and STIP PAYMENT, the year’s amount shall be the sum of the SALARY and STIP PAYMENT, if any, paid or payable in the same calendar year.  If an ELIGIBLE EMPLOYEE has fewer than three years’ SALARY, the average shall be the combination of SALARY and STIP PAYMENT for such shorter time, divided by the number of years and partial years during which such employee was an ELIGIBLE EMPLOYEE.

The BASIC SERP BENEFIT is further reduced by any amounts paid or payable from the RETIREMENT PLAN (other than amounts paid or payable under Part III of the RETIREMENT PLAN), calculated before adjustments for marital or joint pension option elections.

The BASIC SERP BENEFIT is a benefit commencing at age 65.  The amount of the benefit payable shall be reduced by the appropriate age and service factors contained in the RETIREMENT PLAN applicable to such employee.  For such calculations, the service factor shall be SERVICE as defined in the PLAN.

In computing amounts payable from the RETIREMENT PLAN as an offset to the benefit payable from this PLAN, the RETIREMENT PLAN benefit shall be calculated as though the ELIGIBLE EMPLOYEE elected to receive a pension from the RETIREMENT PLAN commencing on the same date as benefits from this PLAN.

2.02For ELIGIBLE EMPLOYEES of the PARTICIPATING EMPLOYERS, who transfer from any of said companies to another subsidiary or affiliate, the principles of Section 10 of the RETIREMENT PLAN shall govern the calculation of benefits under this PLAN.

2.03 An ELIGIBLE EMPLOYEE may elect to have his BASIC SERP BENEFIT paid in any one of the following forms that are actuarially equivalent within the meaning of Treasury Regulations Section 1.409A-2(b)(ii), with the first annuity payment commencing at the time set forth in Section 2.01:

(a) BASIC SERP BENEFIT, or a reduced BASIC SERP BENEFIT as calculated under Section 2.02, paid as a monthly annuity for the life of the ELIGIBLE EMPLOYEE with no survivor’s benefit.

(b) A monthly annuity payable for the life of the ELIGIBLE EMPLOYEE with a survivor’s option payable to the ELIGIBLE EMPLOYEE’s joint annuitant beginning on the first of the month following the ELIGIBLE EMPLOYEE’s death.  Subject to the requirements of Treasury Regulations Section 1.409A-2(b)(ii), the factors to be applied to reduce the BASIC SERP BENEFIT to provide for a survivor’s benefit shall be the factors which are contained in the RETIREMENT PLAN and which are appropriate given the type of joint pension elected and the ages and marital status of the joint annuitants.

An ELIGIBLE EMPLOYEE may make this election by the latest date permitted by the PLAN ADMINISTRATOR and in compliance with the rules of Treasury Regulations Section 1.409A-2(b)(2)(ii).

2.04 Annuities payable to an ELIGIBLE EMPLOYEE who is receiving a (i) BASIC SERP BENEFIT, (ii) a BASIC SERP BENEFIT reduced to provide a survivor’s benefit to a joint annuitant, or (iii) a joint annuitant who is receiving a survivor’s benefit shall be decreased by any additional amounts which can be paid from the RETIREMENT PLAN where such additional amounts are due to increases in the limits placed on benefits payable from qualified pension plans under Section 4l5 of the Internal Revenue Code.  The amount of any such decrease shall be adjusted to reflect the type of pension elected by an ELIGIBLE EMPLOYEE under the RETIREMENT PLAN and this PLAN.

ARTICLE 3                      

SURVIVOR BENEFITS

3.01In the event that an ELIGIBLE EMPLOYEE who has accrued a benefit under this PLAN dies prior to the date that a BASIC SERP BENEFIT would otherwise commence, the PLAN ADMINISTRATOR shall pay a survivor’s benefit (“SURVIVOR’S BENEFIT”) to the ELIGIBLE EMPLOYEE’s surviving spouse or BENEFICIARY (“Beneficiary” shall have the same meaning as provided under the RETIREMENT PLAN):

(a)If the sum of the age and SERVICE of the ELIGIBLE EMPLOYEE at the time of death equaled 70 (69.5 or more is rounded to 70) or if the ELIGIBLE EMPLOYEE was age 55 or older at the time of death, the surviving spouse’s or BENEFICIARY’s benefit shall be a monthly annuity commencing at the time set forth in Section 2.01 and shall be payable for the life of the surviving spouse or BENEFICIARY.  The amount of the monthly benefit shall be a monthly benefit that is actuarially equivalent to one-half of the monthly BASIC SERP BENEFIT that would have been paid to the ELIGIBLE EMPLOYEE calculated:

(i)as if he had elected to receive a BASIC SERP BENEFIT, without survivor’s option; and

(ii)the monthly annuity starting date was the first of the month following the month in which the ELIGIBLE EMPLOYEE died; and

(iii)without the application of early retirement reduction factors.  However, if the surviving spouse or BENEFICIARY is more than 10 years younger than the ELIGIBLE EMPLOYEE, the amount of the surviving spouse’s or BENEFICIARY’s benefit shall be reduced one-twentieth of 1 percent for each full month in excess of 120 months’ difference in their ages, except that such reduction shall not result in a SURVIVOR’S BENEFIT  lower than would have been payable if the ELIGIBLE EMPLOYEE had retired as of the date of death and elected a 50 percent joint pension with a spouse of the same gender and age as the surviving spouse or BENEFICIARY.

(b)If the ELIGIBLE EMPLOYEE is less than 55 years of age or had fewer than 70 points (as calculated under Section 3.01(a)) at the time of death, the surviving spouse orBENEFICIARY will be entitled to receive a monthly annuity commencing at the time set forth in Section 2.01.  The amount of the monthly annuity payable to the surviving spouse or BENEFICIARY shall be equal to the BASIC SERP BENEFIT converted to a marital joint annuity providing for a 50 percent survivor’s benefit, calculated as if:  1) the ELIGIBLE EMPLOYEE had terminated employment at the date of death, 2) had lived until age 55, 3) had begun to receive PENSION payments at age 55, and 4) had subsequently died.

(c)If a former ELIGIBLE EMPLOYEE was age 55 or older at the time of his death and not yet receiving a SERP BENEFIT under the PLAN, the surviving spouse or BENEFICIARY will be entitled to receive a monthly annuity at the time set forth in Section 2.01 in an amount equal to the BASIC SERP BENEFIT converted to a marital joint annuity providing for a 50 percent survivor’s benefit, calculated as if the former ELIGIBLE EMPLOYEE had begun receiving the converted SERP BENEFIT immediately prior to his death.

(d)If a former ELIGIBLE EMPLOYEE was younger than age 55 and had fewer than 70 points (as calculated under Section 3.01(a)) at the time of his death, the surviving spouse or BENEFICIARY will be entitled to receive a monthly annuity at the time set forth in Section 2.01 in an amount equal to the BASIC SERP BENEFIT converted to a marital joint annuity providing for a 50 percent survivor’s benefit, calculated as if:  1) the former ELIGIBLE EMPLOYEE had survived until age 55, 2) had begun receiving the converted SERP BENEFIT at age 55, and 3) had subsequently died.

3.02A surviving spouse or BENEFICIARY who is entitled to receive a SURVIVOR’S BENEFIT under Section  3.01 shall not be entitled to receive any other benefit under the PLAN.

ARTICLE 4                      

ADMINISTRATIVE PROVISIONS

4.01Administration.  The PLAN shall be administered by the Senior Human Resources Officer of the CORPORATION (“PLAN ADMINISTRATOR”), who shall have the authority to interpret the PLAN and make and revise such rules as he or she deems appropriate.  The PLAN ADMINISTRATOR shall have the duty and responsibility of maintaining records, making the requisite calculations, and disbursing payments hereunder.  The PLAN ADMINISTRATOR’s interpretations, determinations, rules, and calculations shall be final and binding on all persons and parties concerned.

4.02Amendment and Termination.  The CORPORATION may amend or terminate the PLAN at any time, provided, however, that no such amendment or termination shall adversely affect an accrued benefit which an ELIGIBLE EMPLOYEE has earned prior to the date of such amendment or termination, nor shall any amendment or termination adversely affect a benefit which is being provided to an ELIGIBLE EMPLOYEE, surviving spouse, joint annuitant, or beneficiary under Article II or Article III on the date of such amendment or termination.  Anything in this Section 4.02 to the contrary notwithstanding, the CORPORATION may (but is not obligated to) reduce or terminate any benefit to which an ELIGIBLE EMPLOYEE, surviving spouse or joint annuitant, is or may become entitled provided that such ELIGIBLE EMPLOYEE, surviving spouse or joint annuitant is or becomes entitled to an amount equal to such benefit under another plan, practice, or arrangement of the CORPORATION that preserves the time and form of payment rules under the PLAN and otherwise in a manner that complies with Code Section 409A, to the extent required to not violate Code Section 409A.

4.03Nonassignability of Benefits.  Except to the extent otherwise directed by a domestic relations order that the Plan Administrator determines is a Qualified Domestic Relations Order under Section 401(a)(12) of the Internal Revenue Code, the benefits payable under this PLAN or the right to receive future benefits under this PLAN 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 any benefits becomes bankrupt, the interest under the PLAN of the person affected may be terminated by the PLAN ADMINISTRATOR which, in its 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 it deems appropriate.

4.04Nonguarantee of Employment.  Nothing contained in this PLAN shall be construed as a contract of employment between a PARTICPATING EMPLOYER and the ELIGIBLE EMPLOYEE, or as a right of the ELIGIBLE EMPLOYEE to be continued in the employ of a PARTICIPATING EMPLOYER, to remain as an officer of a PARTICIPATING EMPLOYER, or as a limitation on the right of a PARTICIPATING EMPLOYER to discharge any of its employees, with or without cause.

4.05Apportionment of Costs.  The costs of the PLAN may be equitably apportioned by the PLAN ADMINISTRATOR among the PARTICIPATING EMPLOYERS.  Each PARTICIPATING EMPLOYER shall be responsible for making benefit payments pursuant to the PLAN on behalf of its ELIGIBLE EMPLOYEES or for reimbursing the CORPORATION for the cost of such payments, as determined by the CORPORATION in its sole discretion.  In the event the respective PARTICIPATING EMPLOYER fails to make such payment or reimbursement, and the CORPORATION does not exercise its discretion to make the contribution on such PARTICIPATING EMPLOYER’s behalf, future benefit accruals of the ELIGIBLE EMPLOYEES of that PARTICIPATING EMPLOYER shall be suspended.  If at some future date, the PARTICIPATING EMPLOYER makes all past-due contributions, plus interest at a rate determined by the PLAN ADMINISTRATOR in his or her sole discretion, the benefit accrual of its ELIGIBLE EMPLOYEES will be recognized for the period of the suspension.

4.06Benefits Unfunded and Unsecured.  The benefits under this PLAN are unfunded, and the interest under this PLAN of any ELIGIBLE EMPLOYEE and such ELIGIBLE EMPLOYEE’s right to receive a distribution of benefits under this PLAN shall be an unsecured claim against the general assets of the CORPORATION.

4.07 Applicable Law.  All questions pertaining to the construction, validity, and effect of the PLAN 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.  The PLAN is intended to comply with the provisions of Code Section 409A.  However, the CORPORATION makes no representation that the benefits provided under this PLAN will comply with Code Section 409A and makes no undertaking to prevent Code Section 409A from applying to the benefits provided under this PLAN or to mitigate its effects on any deferrals or payments made under this PLAN.

4.08Satisfaction of Claims.  Notwithstanding Section 4.05 or any other provision of the PLAN, the CORPORATION may at any time satisfy its obligations (either on a before-tax or after-tax basis) for any benefits accrued under the PLAN by the purchase from an insurance company of an annuity contract on behalf of an ELIGIBLE EMPLOYEE.  Such purchase shall be in the sole discretion of the CORPORATION and shall be subject to the ELIGIBLE EMPLOYEE’s acknowledgement that the CORPORATION’s obligations to provide benefits hereunder have been discharged, without regard to the payments ultimately made under the contract.  In the event of a purchase pursuant to this Section 4.07, the CORPORATION may in its sole discretion make payments to or on behalf of an ELIGIBLE EMPLOYEE to defray the cost to such ELIGIBLE EMPLOYEE of any personal income tax in connection with the purchase.

 

1 Words in all capitals are defined in Article I.

EX-10.32

.

.Exhibit 10.32

PG&E CORPORATION

DEFINED CONTRIBUTION EXECUTIVE SUPPLEMENTAL RETIREMENT PLAN

Effective as of January 1, 2013 (the “Effective Date”), PG&E Corporation adopts this Plan for the benefit of a select group of management or highly compensated employees of PG&E Corporation and its Participating Subsidiaries.  The Plan is an unfunded arrangement and is intended to be exempt from the participation, vesting, funding and fiduciary requirements set forth in Title I of ERISA.

Article 1 – Definitions

When used in this Plan, the following words, terms and phrases have the meanings given to them in this Article unless another meaning is expressly provided elsewhere in this document. When applying these definitions and any other word, term or phrase used in this Plan, the form of any word, term or phrase will include any and all of its other forms.

1.01           “Account” means the bookkeeping account established for each Eligible Employee as provided in Section 5.01 hereof.

1.02           “AggregatedPlan”means any arrangement that, along with this Plan, would be treated as a single nonqualified deferred compensation plan under Treasury Regulation Section 1.409A-

1(c)(2).

1.03           “Board” means the Board of Directors of Company.

1.04           “Code” means the Internal Revenue Code of 1986, as amended.  Reference to a specific section of the Code shall include such section, any valid regulation promulgated thereunder, and any comparable provision of any future legislation amending, supplementing, or superseding such section.

1.05           “Committee” means the Compensation Committee of the Board, as it may be constituted from time to time.

1.06           “Company” means PG&E Corporation, a California corporation.

1.07           “CompanyContribution” means a deemed contribution that is credited to an Eligible Employee’s Account in accordance with the terms of Article 2 hereof.

1.08           “EligibleEmployee” means any individual who (i) was a participant in the SERP and elects to switch under the Pacific Gas and Electric Company Retirement Plan for Management Employees to a cash-balance formula pension benefit effective January 1, 2014, (ii) becomes an Officer in Bands I-V of Company or a Participating Subsidiary on or after the Effective Date; or (iii) is an employee of Company or a Participating Employer, and is designated as a Plan Participant by the Chief Executive Officer of Company.  Notwithstanding the forgoing, any individual who is a participant in the Excess Plan shall not become an Eligible Employee until January 1 of the calendar year after satisfying any of the criteria in (ii)-(iii) above.  If an individual ceases to be an Officer in Bands I-V or if his or her participation in this Plan is terminated by the Chief Executive Officer, then any accrued benefits will be handled in accordance with Article 6.

1.09           “Employer” means any entity that employs an Eligible Employee, whether that entity is the Company or any of the Participating Subsidiaries designated by the Plan Administrator.

1.10           “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

1.11           “Excess Plan” means the Retirement Excess Plan of the Pacific Gas and Electric Company, as amended from time to time.

1.12           “InvestmentFund” means each deemed investment vehicle which serves as a means to measure value, increases or decreases with respect to an Eligible Employee’s Account.

1.13           “Participating Subsidiary”  means a United States-based subsidiary of Company, which has been designated by the Plan Administrator as a Participating Subsidiary under this Plan and which has agreed to make payments or reimbursements with respect to its Eligible Employees pursuant to Section 11.04.  At such times and under such conditions as the Plan Administrator may direct, one or more other subsidiaries of Company may become Participating Subsidiaries or a Participating Subsidiary may be withdrawn from the Plan.  An initial list of the Participating Subsidiaries is contained in Appendix A to this Plan.

1.14            “Plan” means the PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan.

1.15           “PlanYear” means each calendar year during which the Plan is in effect

1.16           “SERP” means the Supplemental Executive Retirement Plan of PG&E Corporation, as amended from time to time.

1.17           “Salary” means only the gross amount of an Eligible Employee’s base salary as reflected in the payroll records of the applicable Employer.  Salary shall not include amounts received by an employee after such employee ceases to be an Eligible Employee or prior to becoming an Eligible Employee.  Salary shall be calculated before reduction for compensation voluntarily deferred or contributed by the Eligible Employee pursuant to all qualified or nonqualified plans of the applicable Employer and shall be calculated to include amounts not otherwise included in the Eligible Employee’s gross income under Code Sections 125, 132, 402(e)(3), 402(h), or 403(b) pursuant to plans or arrangements established by the Employers; provided, however, that all such amounts will be included in compensation only to the extent that had there been no such plan, the amount would have been payable in cash to the Eligible Employee.  Without limiting the foregoing, “Salary” shall not include any amount paid pursuant to a disability plan or pursuant to a disability insurance policy or distributions from nonqualified deferred compensation plans, incentive payments of any kind, commissions, overtime, fringe benefits, or any non-cash benefit.

1.18           “Separation from Service” means a “separation from service” with Company and its

Affiliates within the meaning of Code Section 409A(a)(2)(A)(i) and related Treasury Regulations and other guidance, as determined by the Plan Administrator in its discretion.

1.19           “STIP Payment” means the gross amount of an Eligible Employee’s bonus under the annual cash Short-Term Incentive Plan adopted and maintained each year by Company or its Participating Subsidiaries.   STIP Payments shall not include amounts received by an employee after such employee ceases to be an Eligible Employee or prior to becoming an Eligible Employee.  For purposes of calculating benefits under the Plan, STIP Payment shall be calculated before reduction for compensation voluntarily deferred or contributed by the Eligible Employee pursuant to all qualified or nonqualified plans of the applicable Employer, and shall be calculated to include amounts not otherwise included in the Eligible Employee’s gross income under Code Sections 125, 132, 402(e)(3), 402(h), or 403(b) pursuant to plans or arrangements established by the Employer; provided, however, that all such amounts will be included in compensation only to the extent that had there been no such plan, the amount would have been payable in cash to the Eligible Employee.

1.20          “ValuationDate”means:

(1)   For purposes of valuing Plan assets and Eligible Employees’ Accounts for periodic reports and statements, the date as of which such reports or statements are made; and

(2)   For purposes of determining the amount of assets actually distributed to the Eligible Employee, his or her beneficiary, or an Alternate Payee (or available for withdrawal), a date that shall not be more than thirty business days prior to the date the check is issued to the Eligible Employee.

In any other case, the Valuation Date shall be the date designated by the Plan Administrator (in its discretion) or the date otherwise set forth in this Plan.  In all cases, the Plan Administrator (in its discretion) may change the Valuation Date, on a uniform and nondiscriminatory basis, as is necessary or appropriate.  Notwithstanding the foregoing, the Valuation Date shall occur at least annually.

                                                          Article 2 - Company Contributions

2.01           CompanyContributions.  Company will make a deemed contribution to each Eligible Employee’s Account in a percentage amount designated by the Committee, in its sole discretion, of the Eligible Employee’s Salary and STIP Payment, at the time that such Salary or STIP Payment is paid.

2.02           Excess Plan Participants.  Company will make an additional deemed contribution to the Account of each Eligible Employee who was a participant in the Excess Plan on or after January 1, 2013. The amount of such contribution will be approximately equal to the difference between the amounts that the Eligible Employee could have received under the Plan if contributions, if any, under Section 2.01 had commenced upon satisfying any of the eligibility criteria in Section 1.08(ii)-(iii), and the amount actually accrued under the Excess Plan, in each case through December 31 of such year. Such payments shall be made only for the portion of the calendar year prior to the individual becoming an Eligible Employee. Such calculation shall be done at the Company’s discretion, using such assumptions and methodologies as determined by the Company in its sole discretion. Amounts provided pursuant to this Section will distributed in a lump-sum, in accordance with Section 6.01(2).

Article 3 - Vesting

3.01           VestingofCompanyContributions.  Except as otherwise determined by the Plan Administrator in its sole discretion, and provided that the Eligible Employee has not Separated from Service, an Eligible Employee shall become one hundred percent (100%) vested in the Eligible Employee’s Account after completing at least three (3) cumulative years of service with any Employer(s).  For this purpose, years of service shall be calculated on an elapsed-time, anniversary date of hire basis.  “Years of cumulative service” shall include all service while an active participant in the Plan or in the SERP, including active service prior to any break in service.  An Employee’s service will be deemed to continue while on approved leave of absence.

3.02           AmountsNotVested.  Subject to the foregoing, any amounts credited to an Eligible Employee’s Account that are not vested at the time of the Eligible Employee’s Separation from Service shall be forfeited.

Article 4 – Investment Funds

Although no assets will be segregated or otherwise set aside with respect to an Eligible Employee’s Account, the amount that is ultimately payable to the Eligible Employee with respect to such Account shall be determined as if such Account had been invested in some or all of the Investment Funds.  The Plan Administrator, in its sole discretion, shall adopt (and modify from time to time) such rules and procedures as it deems necessary or appropriate to implement the deemed investment of the Eligible Employees’ Accounts.  Such procedures generally shall provide that an Eligible Employee’s Account shall be deemed to be invested among the available Investment Funds in the manner elected by the Eligible Employee in such percentages and manner as prescribed by the Plan Administrator.  In the event no election has been made by the Eligible Employee, such Account will be deemed to be invested in the Investment Funds designated by the Plan Administrator.  Eligible Employees shall be able to reallocate their Accounts between the Investment Funds and reallocate amounts newly credited to their Accounts at such time and in such manner as the Plan Administrator shall prescribe.  Anything to the contrary herein notwithstanding, an Eligible Employee may not reallocate Account balances between Investment Funds if such reallocation would result in a non-exempt Discretionary Transaction as defined in Rule 16b-3 of the Securities Exchange Act of 1934, as amended, or any successor to Rule 16b-3, as in effect when the reallocation is requested.  The available Investment Funds shall be designated by the Plan Administrator and may be changed from time to time by the Plan Administrator at its discretion.

Article 5 - Accountings

5.01           Eligible Employees’ Accounts.  At the direction of the Plan Administrator, there shall be established and maintained on the books of the Employer, a separate account for each Eligible Employee in order to reflect his or her interest under the Plan.

5.02           Investment Earnings.  Each Eligible Employee’s Account shall initially reflect the value of his or her Account’s interest in each of the Investment Funds, deemed acquired with the amounts credited thereto.  Each Eligible Employee’s Account shall also be credited (or debited) with the net appreciation (or depreciation), earnings and gains (or losses) with respect to the investments deemed made by his or her Account.  Any such net earnings or gains deemed realized with respect to any investment of any Eligible Employee’s Account shall be deemed reinvested in additional amounts of the same investment and credited to the Eligible Employee’s Account.

5.03           Accounting Methods.  The accounting methods or formulae to be used under the Plan for the purpose of maintaining the Eligible Employees’ Accounts shall be determined by the Plan Administrator.  The accounting methods or formulae selected by the Plan Administrator may be revised from time to time but shall conform to the extent practicable with the accounting methods used under the Plan.

5.04           Valuations and Reports.  The fair market value of each Eligible Employee’s Account shall be determined as of each Valuation Date.  In making such determinations and in crediting net deemed earnings and gains (or losses) in the Investment Funds to the Eligible Employees’ Accounts, the Plan Administrator (in its discretion) may employ such accounting methods as the Plan Administrator (in its discretion) may deem appropriate in order to fairly reflect the fair market values of the Investment Funds and each Eligible Employee’s Account.  For this purpose, the Plan Administrator may rely upon information provided by the Plan Administrator or other persons believed by the Plan Administrator to be competent.

5.05           Statements of Eligible Employee’s Accounts.  Each Eligible Employee shall be furnished with periodic statements of his or her interest in the Plan.

Article 6 - Distributions.

6.01           Distribution of Account Balances.

(1) Participants in SERP.  Distribution of the balance credited to the Account of any Eligible Employee who was a participant in the SERP will be made according to the time and form provisions applicable to that Eligible Employee’s benefits under the SERP.  Sections 6.01(2), 6.02, 6.03, 6.04 and 6.05 shall not apply to the Eligible Employees described above in this Section 6.01(1).

(2) Other Eligible Employees.  Except to the extent the Eligible Employee has elected otherwise under this Section 6 at the time of deferral, distribution of the balance credited to an Eligible Employee’s Account shall be made in a single lump sum as soon as reasonably practicable (but in any event within 90 days) following the date that is seven (7) months following Separation from Service.

(3) DROs.  In the case of an Alternate Payee (as defined in Section 7.01(1)), to the extent allowable under Code Section 409A, distribution shall be made as directed in a domestic relations order approved by the Plan Administrator, but only as to the portion of the Eligible Employee’s Account which the domestic relations order states is payable to the Alternate Payee.

6.02           Election of Installment Payments.  In lieu of the single sum payment under Section 6.01, an Eligible Employee may elect in writing, on such form or in such other manner as it may prescribe, and file with the Plan Administrator an election that payment of amounts credited to the Eligible Employee’s Account be made in from 2 to 10 equal annual installments.  Installment payments will be considered separate payments for purposes of Code Section 409A and will commence as soon as reasonably practicable (but in any event within 90 days) following the date that is seven (7) months following Separation from Service ("Benefit Commencement Date"), and subsequent installments will be paid on each anniversary of the Benefit Commencement Date thereof until all installments are paid.  However, if during the installment payment period after the Benefit Commencement Date the Account balance plus the Eligible Employee’s interest in all other Aggregated Plans is less than the dollar limit set forth in Code Section 402(g)(1)(B) in the aggregate, the value of the remaining installments and such other interest(s) may be accelerated by written election of the Plan Administrator and subsequently paid as a lump sum at the sole discretion of the Plan Administrator, except to the extent that would result in a violation of Code Section 409A.  Notwithstanding anything in this Section 6.02 to the contrary, if the Eligible Employee’s vested Account balance on the Benefit Commencement Date is less than $50,000, then the distribution election described in this Section 6.02 shall be disregarded and the Eligible Employee’s entire vested Account balance shall be paid in a lump sum distribution as described in Section 6.01(2) above.

6.03           Timing of Elections.

(1)   General Rule.  The election described in Section 6.02 shall be made no later than December 31 of the calendar year immediately preceding the calendar year in which the Salary or STIP Payment commences to be earned that is the basis of the Company Contribution for which an election is being made, in accordance with such procedures established by the Company in its sole discretion.

(2)   Initial Eligibility.  Notwithstanding Section 6.03(1), an Eligible Employee that is newly eligible to participate in the Plan (or in any Aggregated Plan) must make an election regarding whether distributions shall be made in a lump-sum or installments, as provided in Section 6.02.  Such election must be made within thirty (30) days after he or she first becomes an Eligible Employee (or within such other earlier deadline as may be established by the Company, in its sole discretion) but only with respect to Company Contributions attributable to Salary and STIP Payments that are paid with respect to services performed after such election is made; provided, however, that for this purpose only such thirty (30) day period shall begin to run on the date that the Eligible Employee first becomes eligible to participate in this Plan (or, if earlier, any Aggregated Plan). In the event an Eligible Employee fails to timely make such election, Section 6.01(2) shall apply.   Notwithstanding anything to the contrary herein, no Company Contributions shall be earned or made to a newly Eligible Employee’s Account with respect to service performed prior to the earlier of (1) the day after the Eligible Employee returns an initial election pursuant to Section 6.03(2) or (2) 31 days after the individual first qualifies as an Eligible Employee.

(3)Performance-Based Compensation.  Notwithstanding Section 6.03(1), with respect toSTIP Payments that qualify as “Performance-Based Compensation,” the Company may, inits sole discretion, permit an election pertaining to Company Contributions attributable to such Performance-Based Compensation to be made no later than six (6) months before the end of the performance service period and in accordance with Code Section 409A.  For this purpose, “Performance-Based Compensation” shall be compensation, the payment or amount of which is contingent on pre-established organizational or individual performance criteria, which satisfies the requirements of Code Section 409A.

6.04           Change in Distribution Election.  An Eligible Employee may change a distribution election previously made pursuant to Section 6.02 only in accordance with the rules under Code Section 409A.  Generally, a subsequent election pursuant to this Section 6.04:  (1) cannot take effect for twelve (12) months, (2) must occur at least twelve (12) months before the first scheduled payment, and (3) must defer a previously elected distribution at least five (5) additional years.  The Plan Administrator may establish additional rules or restrictions on changes in distribution elections.

6.05           Death Distributions.  If an Eligible Employee dies before the balance of his or her Account has been distributed (whether or not the Eligible Employee had previously  had a Separation from Service), the Eligible Employee’s Account shall be distributed in a single lump sum to the beneficiary designated or otherwise determined in accordance with Section 6.07, as soon as practicable the date of death (but in any event within 90 days after the date of death).

 6.06           Effect of Change in Eligible Employee Status.  If an Eligible Employee ceases to be an Eligible Employee but does not experience a Separation from Service, the balance credited to his or her Account shall continue to be credited (or debited) with appreciation, depreciation, earnings, gains or losses under the terms of the Plan and shall be distributed to him or her at the time and in the manner set forth in this Section 6.

6.07           Payments to Incompetents.  If any individual to whom a benefit is payable under the Plan is a minor or if the Plan Administrator determines that any individual to whom a benefit is payable under the Plan is incompetent to receive such payment or to give a valid release therefor, payment shall be made to the guardian, committee, or other representative of the estate of such individual which has been duly appointed by a court of competent jurisdiction.  If no guardian, committee, or other representative has been appointed, payment may be made to any person as custodian for such individual under the California Uniform Transfers to Minors Act (or similar law of another state) or may be made to or applied to or for the benefit of the minor or incompetent, the incompetent’s spouse, children or other dependents, the institution or persons maintaining the minor or incompetent, or any of them, in such proportions as the Plan Administrator from time to time shall determine; and the release of the person or institution receiving the payment shall be a valid and complete discharge of any liability of Company with respect to any benefit so paid.

6.08           Beneficiary Designations.  Each Eligible Employee may designate, in a signed writing delivered to the Plan Administrator, on such form or in such other manner as it may prescribe, one or more beneficiaries to receive any distribution which may become payable under the Plan as the result of the Eligible Employee’s death.  Such an Eligible Employee may designate different beneficiaries at any time by delivering a new designation in like manner.  Any designation shall become effective only upon its receipt by the Plan Administrator, and the last effective designation received by the Plan Administrator shall supersede all prior designations.  If such an Eligible Employee dies without having designated a beneficiary or if no beneficiary survives that Eligible Employee, that Eligible Employee’s Account shall be payable to the beneficiary or beneficiaries designated or otherwise determined under the PG&E Corporation Retirement Savings Plan or any predecessor qualified retirement plan sponsored by Company or any of its subsidiary companies.

6.09           Undistributable Accounts.  Each Eligible Employee and (in the event of death) his or her beneficiary shall keep the Plan Administrator advised of his or her current address.  If the Plan Administrator is unable to locate the Eligible Employee or beneficiary to whom an Eligible Employee’s Account is payable under this Section 6, the Eligible Employee’s Account shall be frozen as of the date on which distribution would have been completed in accordance with this Section 6, and no further appreciation, depreciation, earnings, gains or losses shall be credited (or debited) thereto.  Company shall have the right to assign or transfer the liability for payment of any undistributable Account to the Eligible Employee’s former Employer (or any successor thereto).

6.10           Plan Administrator Discretion.  Within the specific time periods described in this Section 6, the Plan Administrator shall have sole discretion to determine the specific timing of the payment of any Account balance under the Plan.

Article 7 - Domestic Relations Orders.

7.01           Domestic Relations Orders.  The Plan Administrator shall establish written procedures for determining whether a domestic relations order purporting to dispose of any portion of an Eligible Employee’s Account is a domestic relations order within the meaning of Section 414(p) of the Code that is acceptable to the Plan (a “DRO”).

(1)   No Payment Unless a DRO.  No payment shall be made to any person designated in a domestic relations order (an “Alternate Payee”) until the Plan Administrator (or a court of competent jurisdiction reversing an initial adverse determination by the Plan Administrator) determines that the order is a DRO.  Payment shall be made to each Alternate Payee as specified in the DRO.

(2)   Time of Payment.  Payment may be made to an Alternate Payee in the form of a lump sum, at the time specified in the DRO, but no earlier than the date the DRO determination is made by the Plan.

(3)   Hold Procedures.  Notwithstanding any contrary Plan provision, prior to the receipt of a domestic relations order, the Plan Administrator may, in its sole discretion, place a hold upon all or a portion of an Eligible Employee’s Account for a reasonable period of time (as determined by the Plan Administrator in accordance with Code Section 409A) if the Plan Administrator receives notice that (a) a domestic relations order is being sought by the Eligible Employee, his or her spouse, former spouse, child or other dependent, and (b) the Eligible Employee’s Account is a source of the payment under such domestic relations order.  For purposes of this Section 7.01, a “hold” means that no withdrawals, distributions, or investment transfers may be made with respect to an Eligible Employee’s Account.  If the Plan Administrator places a hold upon an Eligible Employee’s Account pursuant to this Section 7.01, it shall inform the Eligible Employee of such fact.

Article 8 - Tax Withholding

Each Eligible Employee shall be responsible for FICA taxes on amounts credited to his or her Account under Section 2.  Without limiting the foregoing, the applicable Employer shall have the right to withhold such amounts from other payments due to the Eligible Employee.  Company Contributions will not be reduced to cover Eligible Employees’ FICA tax liabilities.

The applicable Employer, as applicable, will withhold from other amounts owed to an Eligible Employee or require the Eligible Employee to remit to Employer, as applicable, an amount sufficient to satisfy federal, state and local tax withholding requirements with respect to any Plan benefit or the vesting, payment or cancellation of any Plan benefit.

Article 9 - Administration of the Plan.

9.01           Plan Administrator.  The Employee Benefit Committee of Company is hereby designated as the administrator of the Plan (within the meaning of Section 3(16)(A) of ERISA).  The Plan Administrator delegates to the most senior human resource officer for Company, or his or her designee, the authority to carry out all duties and responsibilities of the Plan Administrator under the Plan.  The Plan Administrator shall have the authority to control and manage the operation and administration of the Plan.

9.02           Powers of Plan Administrator.  The Plan Administrator shall have all discretion and powers necessary to supervise the administration of the Plan and to control its operation in accordance with its terms, including, but not by way of limitation, the power to interpret the provisions of the Plan and to determine, in its sole discretion, any question arising under, or in connection with the administration or operation of, the Plan.

9.03           Decisions of Plan Administrator.  All decisions of the Plan Administrator and any action taken by it in respect of the Plan and within the powers granted to it under the Plan shall be conclusive and binding on all persons and shall be given the maximum deference permitted by law.

Article 10 - Modification or Termination of Plan.

10.01  Employers’ Obligations Limited.  The Plan is voluntary on the part of the Employers, and the Employers do not guarantee to continue the Plan.  Company at any time may, by appropriate amendment of the Plan, or suspend Company Contributions , with or without cause.

10.02           Right to Amend or Terminate.  The Board of Directors, acting through the Committee, reserves the right to alter, amend, or terminate the Plan, or any part thereof, in such manner as it may determine, for any reason whatsoever.

(1)   Limitations.  Any alteration, amendment, or termination shall take effect upon the date indicated in the document embodying such alteration, amendment, or termination, provided that no such alteration or amendment shall divest any portion of an Account that is then vested under the Plan.

(2)   Appendices.  Notwithstanding the above, the Plan Administrator may amend the Appendices in its discretion.

10.03           Effect of Termination.  If the Plan is terminated, the balances credited to the Accounts of the Eligible Employees affected by such termination shall be distributed to them at the time and in the manner set forth in Section 6; provided, however, that the Plan Administrator, in its sole discretion, may authorize accelerated distribution of Eligible Employees’ Accounts to the extent provided in Treasury Regulation Sections 1-409A-3(j)(4)(ix) (A) (relating to terminations in connection with certain corporate dissolutions), (B) (relating to terminations in connection with certain change of control events), and (C) (relating to general terminations).

Article 11 - General Provisions

11.01           Inalienability.  Except to the extent otherwise directed by a domestic relations order which the Plan Administrator determines is a DRO (as defined in Section 7.01) or mandated by applicable law, in no event may either an Eligible Employee, a former Eligible Employee or his or her spouse, beneficiary or estate sell, transfer, anticipate, assign, hypothecate, or otherwise dispose of any right or interest under the Plan; and such rights and interests shall not at any time be subject to the claims of creditors nor be liable to attachment, execution, or other legal process.

11.02           Rights and Duties.  Neither the Employers nor the Plan Administrator shall be subject to any liability or duty under the Plan except as expressly provided in the Plan, or for any action taken, omitted, or suffered in good faith.

11.03           No Enlargement of Employment Rights.  Neither the establishment or maintenance of the Plan nor any action of any Employer or Plan Administrator, shall be held or construed to confer upon any individual any right to be continued as an Employee nor, upon dismissal, any right or interest in any specific assets of the Employers other than as provided in the Plan.  Each Employer expressly reserves the right to discharge any Employee at any time, with or without cause or advance notice.

11.04.           Apportionment of Costs and Duties.  All acts required of the Employers under the Plan may be performed by Company for itself and its Participating Subsidiaries, and the costs of the Plan may be equitably apportioned by the Plan Administrator among Company and the other Employers.  Whenever an Employer is permitted or required under the terms of the Plan 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 Participating Subsidiary shall be responsible for making benefit payments pursuant to the Plan on behalf of its Eligible Employees or for reimbursing Company for the cost of such payments, as determined by Company in its sole discretion.  In the event the respective Participating Subsidiary fails to make such payment or reimbursement, and Company does not exercise its discretion to make the payment on such Participating Subsidiary’s behalf, participation in the Plan by the Eligible Employees of that Participating Subsidiary shall be suspended in a manner consistent with Code Section 409A.  If at some future date, the Participating Subsidiary makes all past-due payments and reimbursements, plus interest at a rate determined by Company in its sole discretion, the suspended participation of its Eligible Employees eligible to participate in the Plan will be recognized in a manner consistent with Code Section 409A.  In the event the respective Participating Subsidiary fails to make such payment or reimbursement, an Eligible Employee’s (or other payee’s) sole recourse shall be against the respective Participating Subsidiary, and not against Company.  An Eligible Employee’s participation in the Plan shall constitute agreement with this provision.

11.05           Applicable Law.  The provisions of the Plan shall be construed, administered, and enforced in accordance with the laws of the State of California and, to the extent applicable, ERISA.  The Plan is intended to comply with the provisions of Code Section 409A.  However, Company makes no representation that the benefits provided under the Plan will comply with Code Section 409A and makes no undertaking to prevent Code Section 409A from applying to the benefits provided under the Plan or to mitigate its effects on any deferrals or payments made under the Plan.

11.06           Severability.  If any provision of the Plan is held invalid or unenforceable, its invalidity or unenforceability shall not affect any other provisions of the Plan, and the Plan shall be construed and enforced as if such provision had not been included.

11.07           Captions.  The captions contained in and the table of contents prefixed to the Plan are inserted only as a matter of convenience and for reference and in no way define, limit, enlarge, or describe the scope or intent of the Plan nor in any way shall affect the construction of any provision of the Plan.

APPENDIX A

PARTICIPATING SUBSIDIARIES

(As of January 1, 2013)

– Pacific Gas and Electric Company

– All U.S. subsidiaries of PG&E Corporation or the above-named corporation(s)

EX-10.36

Exhibit 10.36

Director Compensation

RESOLUTION OF THE

BOARD OF DIRECTORS OF

PG&E CORPORATION

September 18, 2012

BE IT RESOLVED that, effective January 1, 2013, 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 $15,000 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, 2013, 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, 2013, 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, the non-employee director who is duly appointed to chair the Compensation Committee of this Board shall be paid an additional retainer of $3,750, 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, 2013, 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, 2013, 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, 2013, the resolution on this subject adopted by the Board of Directors on December 15, 2010 is hereby superseded.

2

EX-10.37

Exhibit 10.37

Director Compensation

RESOLUTION OF THE

BOARD OF DIRECTORS OF

PACIFIC GAS AND ELECTRIC COMPANY

September 18, 2012

BE IT RESOLVED that, effective January 1, 2013, 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 $15,000 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, 2013, 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, 2013, 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, 2013, 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, 2013, 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, 2013, the resolution on this subject adopted by the Board of Directors on December 15, 2010 is hereby superseded.

2

EX-10.40

Exhibit 10.40

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		15
7.2		16
7.3		17
8.	Terms and Conditions of Stock Appreciation Rights
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
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

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.
June 15, 2011	Plan is amended such that the number of annual RSUs granted to Nonemployee directors is rounded down to the nearest whole number.  (Previously, the number of RSUs granted included fractional units calculated to three decimal points.)
January 1, 2013	Section 7 of the Plan is amended to (1) increase the value of annual equity awards to Nonemployee Directors from $90,000 to $105,000 and (2) permit deferral of non-employee director awards that are granted pursuant to section 7 of the Plan.

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, December 15, 2010, June 15, 2011, and January 1, 2013)

1.Establishment, Purpose and Term of Plan.

1.1Establishment.  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.

1.2Purpose.  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.

1.3Term 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.

2.1Definitions. 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.

(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 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:

(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.

(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.

(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 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.

2.2Construction.  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.

3.1Administration 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.

3.2Authority 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.

3.3Administration 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.

3.4Committee 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).

3.5Powers 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, (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.

3.6Option 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 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.

3.7Indemnification.  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.

4.1Maximum 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.

4.2Adjustments 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 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.

5.1Persons 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.

5.2Participation.  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.

5.3Incentive 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.

(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.

5.4Award 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.

(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:

6.1Exercise 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.

6.2Exercisability 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 shall terminate ten (10) years after the effective date of grant of the Option, unless earlier terminated in accordance with its provisions.

6.3Payment 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.

6.4Effect 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 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.

6.5Transferability 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.

7.1Grant 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 $105,000 by the Fair Market Value of the Stock on the Grant Date (rounded down to the nearest whole Restricted Stock Unit).  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 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.  However, commencing with Restricted Stock Units having a Grant Date in 2013, a Nonemployee Director may irrevocably elect, no later than December 31 of the calendar year prior to the Grant Date of the Restricted Stock Units (or such later time permitted by Section 409A) to have the Nonemployee Director’s Restricted Stock Unit account settled in (1) a series of 10 approximately equal annual installments (which shall be separate payments for purposes of Section 409A) commencing in January of any year following the normal vesting date, or (2) a lump sum in January of any future year following the normal vesting date.  In the event that the Nonemployee Director elects settlement of the Restricted Stock Units in accordance with the immediately preceding sentence, the Restricted Stock Units shall be earlier settled in a lump sum upon the occurrence of any of the events set forth in Section 7.1(c)(ii) through 7.1(c)(v) prior to the elected settlement date (or commencement thereof in the case of settlement in 10 equal annual installments).  In the event that a Nonemployee Director elects to have the Nonemployee Director’s Restricted Stock Unit account settled in a series of 10 approximately equal annual installments commencing in January of any year following the normal vesting date and one of the events set forth in Section 7.1(c)(ii) through 7.1(c)(v) occurs after commencement of such installments but prior to full settlement of the Nonemployee Director’s Restricted Stock Units, then any remaining unsettled Restricted Stock Units will be settled in a lump sum upon the occurrence of the applicable event but only to the extent that such acceleration would not result in the imposition of taxation under Section 409A.

7.2Effect 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.

7.3Effect 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 such time set forth 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:

8.1Types 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.

8.2Exercise 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.

8.3Exercisability 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.

8.4Deemed 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.

8.5Effect 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.

8.6Nontransferability 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:

9.1Types 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).

9.2Purchase 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.

9.3Purchase 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.

9.4Vesting 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 hereunder for the placement on such certificates of appropriate legends evidencing any such transfer restrictions.

9.5Voting 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.

9.6Effect 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.

9.7Nontransferability 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:

10.1Types 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 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.

10.2Initial 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.

10.3Establishment 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.

10.4Measurement 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) 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.

10.5Settlement 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.

10.6Voting 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 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.

10.7Effect 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.

10.8Nontransferability 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 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:

11.1Grant 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).

11.2Vesting.  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.

11.3Voting 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 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.

11.4Effect 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.

11.5Settlement 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.

11.6Nontransferability 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.

12.1Establishment 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.

(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.

12.2Terms 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 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.

14.1Effect 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.

14.2Effect 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.

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

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.

16.1Tax 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.

16.2Withholding 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.  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.

18.1Repurchase 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.

18.2Provision 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.

18.3Rights 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.

18.4Rights 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.

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

18.6Severability.  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.

18.7Beneficiary 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.

18.8Unfunded 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.

18.9Choice 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.

18.10Section 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%) 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.

EX-12.01

EXHIBIT 12.1

PACIFIC GAS AND ELECTRIC COMPANY

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Year ended December 31,
	2012		2011		2010		2009		2008
Earnings:
Net income	$	811	$	845	$	1,121	$	1,250	$	1,199
Income taxes provision		298		480		574		482		488
Net fixed charges		891		880		799		817		860
Total Earnings	$	2,000	$	2,205	$	2,494	$	2,549	$	2,547
Fixed Charges:
Interest on short-term borrowings and long-term debt, net		834		824		731		754	$	794
Interest on capital leases		9		16		18		19		22
AFUDC debt		48		40		50		44		44
Total Fixed Charges	$	891	$	880	$	799	$	817	$	860
Ratios of Earnings to Fixed Charges		2.24		2.51		3.12		3.12		2.96

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.  Fixed charges exclude interest on tax liabilities.

..

EX-12.02

.

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:	2012		2011		2010		2009		2008
Net income	$	811	$	845	$	1,121	$	1,250	$	1,199
Income taxes provision		298		480		574		482		488
Fixed charges		891		880		799		817		860
Total Earnings	$	2,000	$	2,205	$	2,494	$	2,549	$	2,547
Fixed Charges:
Interest on short-term borrowings and long-term debt, net	$	834	$	824	$	731	$	754	$	794
Interest on capital leases		9		16		18		19		22
AFUDC debt		48		40		50		44		44
Total Fixed Charges	$	891	$	880	$	799	$	817	$	860
Preferred Stock Dividends:
Tax deductible dividends		9		9		9		9		9
Pre-tax earnings required to cover non-tax deductible preferred stock dividend requirements		7		8		7		7		7
Total Preferred Stock Dividends		16		17		16		16		16
Total Combined Fixed Charges and Preferred Stock Dividends	$	907	$	897	$	815	$	833	$	876
Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends		2.21		2.46		3.06		3.06		2.91

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. “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-12.03

.

EXHIBIT 12.3

PG&E CORPORATION

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Year Ended December 31,
	2012			2011			2010			2009			2008
Earnings:
Income from continuing operations	$	830		$	858		$	1,113		$	1,234		$	1,198
Income taxes provision		237			440			547			460			425
Fixed charges		931			919			850			877			907
Pre-tax earnings required to cover the preferred stock dividend of consolidated subsidiaries		(15	)		(17	)		(16	)		(16	)		(16	)
Total Earnings	$	1,983		$	2,200		$	2,494		$	2,555		$	2,514
Fixed Charges:
Interest and amortization of premiums, discounts and capitalized expenses related to short-term borrowings and long-term debt, net	$	859		$	846		$	766		$	798		$	825
Interest on capital leases		9			16			18			19			22
AFUDC debt		48			40			50			44			44
Pre-tax earnings required to cover the preferred stock dividend of consolidated subsidiaries		15			17			16			16			16
Total Fixed Charges	$	931		$	919		$	850		$	877		$	907
Ratios of Earnings to Fixed Charges	$	2.13		$	2.39			2.93			2.91			2.77

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

Selected Financial Data		2
Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Overview	3
	Cautionary Language Regarding Forward Looking Statements	6
	Results of Operations	9
	Liquidity and Financial Resources	15
	Contractual Commitments	22
	Capital Expenditures	23
	Natural Gas Matters	23
	Regulatory Matters	28
	Environmental Matters	31
	Legal Matters	33
	Off-Balance Sheet Arrangements	33
	Risk Management Activities	34
	Critical Accounting Policies	35
	Risk Factors	38
PG&E Corporation
	Consolidated Statements of Income	50
	Consolidated Statements of Comprehensive Income	51
	Consolidated Balance Sheets	52
	Consolidated Statements of Cash Flows	54
	Consolidated Statements of Equity	55
Pacific Gas and Electric Company
	Consolidated Statements of Income	56
	Consolidated Statements of Comprehensive Income	57
	Consolidated Balance Sheets	58
	Consolidated Statements of Cash Flows	60
	Consolidated Statements of Shareholders’ Equity	61
Notes to the Consolidated Financial Statements
	Note 1: Organization and Basis of Presentation	62
	Note 2: Summary of Significant Accounting Policies	62
	Note 3: Regulatory Assets, Liabilities, and Balancing Accounts	68
	Note 4: Debt	72
	Note 5: Energy Recovery Bonds	74
	Note 6: Common Stock and Share-Based Compensation	75
	Note 7: Preferred Stock	77
	Note 8: Earnings Per Share	78
	Note 9: Income Taxes	79
	Note 10: Derivatives	82
	Note 11: Fair Value Measurements	85
	Note 12: Employee Benefit Plans	92
	Note 13: Resolution of Remaining Chapter 11 Disputed Claims	100
	Note 14: Related Party Agreements and Transactions	101
	Note 15: Commitments and Contingencies	102
Quarterly Consolidated Financial Data (Unaudited)		113
Management’s Report on Internal Control Over Financial Reporting		114
Reports of Independent Registered Public Accounting Firm		115

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SELECTED FINANCIAL DATA

(in millions, except per share amounts)	2012		2011		2010		2009		2008 (1)
PG&E Corporation
For the Year
Operating revenues	$	15,040	$	14,956	$	13,841	$	13,399	$	14,628
Operating income		1,693		1,942		2,308		2,299		2,261
Income from continuing operations		830		858		1,113		1,234		1,198
Earnings per common share from continuing operations, basic		1.92		2.10		2.86		3.25		3.23
Earnings per common share from continuing operations, diluted		1.92		2.10		2.82		3.20		3.22
Dividends declared per common share (2)		1.82		1.82		1.82		1.68		1.56
At Year-End
Common stock price per share	$	40.18	$	41.22	$	47.84	$	44.65	$	38.71
Total assets		52,449		49,750		46,025		42,945		40,860
Long-term debt (excluding current portion)		12,517		11,766		10,906		10,381		9,321
Capital lease obligations (excluding current portion) (3)		113		212		248		282		316
Energy recovery bonds (excluding current portion) (4)		-		-		423		827		1,213
Pacific Gas and Electric Company For the Year
Operating revenues	$	15,035	$	14,951	$	13,840	$	13,399	$	14,628
Operating income		1,695		1,944		2,314		2,302		2,266
Income available for common stock		797		831		1,107		1,236		1,185
At Year-End
Total assets		51,923		49,242		45,679		42,709		40,537
Long-term debt (excluding current portion)		12,167		11,417		10,557		10,033		9,041
Capital lease obligations (excluding current portion) (3)		113		212		248		282		316
Energy recovery bonds (excluding current portion) (4)		-		-		423		827		1,213

(1) In 2008, PG&E Corporation recorded $154 million in income from discontinued operations related to losses incurred and synthetic fuel tax credits claimed by PG&E Corporation’s former subsidiary, National Energy & Gas Transmission, Inc.

(2) Information about the frequency and amount of dividends and restrictions on the payment of dividends is set forth in “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.

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

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

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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 that conducts its business 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 electricity distribution customers and approximately 4.4 million natural gas distribution customers at December 31, 2012.

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 electricity 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.  The Utility also is subject to the jurisdiction of other federal, state, and local governmental agencies.

Before setting rates, the CPUC and the FERC conduct proceedings to 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 (depreciation, tax, and financing expenses) of providing utility services.  The primary CPUC proceedings are the general rate case (“GRC”) and the gas transmission and storage (“GT&S”) rate case which generally occur every few years and result in revenue requirements that are set for multi-year periods.  The CPUC also periodically conducts a cost of capital proceeding, where it determines the capital structure the Utility must maintain (i.e., the relative weightings of common equity, long-term debt, and preferred equity) and authorizes the Utility to earn a specific rate of return on each capital component, including a rate of return on equity (“ROE”).  The authorized revenue requirements the CPUC sets in the GRC and GT&S rate cases are set at levels to provide the Utility an opportunity to earn its authorized rates of return on its “rate base” – the Utility’s net investment in facilities, equipment, and other property used or useful in providing utility service to its customers.  The primary FERC proceeding is the electric transmission owner (“TO”) rate case which generally occurs on an annual basis.  The FERC does not conduct a separate proceeding to authorize a specific rate of return on the Utility’s FERC-jurisdictional assets.  Instead, the rate of return is embedded in electric transmission revenues authorized by the FERC in TO rate cases.  If the outcome of a TO rate case is reached through a FERC-approved settlement, the rate of return may not be specifically identified but rates would have been set to provide the Utility an opportunity to earn a reasonable rate of return.  In other TO rate cases, the FERC may determine a specific rate of return after the FERC has held hearings and the parties have submitted briefs.

The Utility’s ability to recover the revenue requirements that have been 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 and the amount and timing of capital expenditures may impact the Utility’s ability to earn its authorized rate of return.  The Utility’s ability to recover a portion of its revenue requirements that have been authorized by the CPUC in GT&S rate cases depends on the volume of natural gas transported.  The Utility’s ability to recover its revenue requirements that have been authorized by the FERC in a TO rate case depends on the volume of electricity sales.

The Utility also collects additional revenue requirements to recover certain costs that the CPUC has authorized the Utility to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose, demand response, and customer energy efficiency programs.  Therefore, although the timing and amount of these costs can impact the Utility’s revenue, these costs generally do not impact net income.  The Utility’s revenues and net income, however, also may be affected by incentive ratemaking mechanisms that adjust rates depending on the extent to which the Utility meets or fails to meet certain performance criteria, such as customer energy efficiency goals.

The Utility’s revenue requirements are set based on forecasted costs.  Differences in actual costs could negatively affect the Utility’s ability to earn its authorized return.  Differences can occur for numerous reasons, including unanticipated costs related to storms, outages, catastrophic events, or to comply with new legislation, regulations, or orders; or if the Utility is required to pay third-party claims that are not recoverable through insurance.  The CPUC could also disallow recovery of costs that it finds were not prudently or reasonably incurred.  Finally, there may be some types of costs that the CPUC has determined will not be recoverable through rates or for which the Utility does not seek recovery, such as certain costs associated with the Utility’s natural gas system, penalties associated with investigations or violations, and environmental-related liabilities associated with the Utility’s natural gas compressor station located in Hinkley, California, as described more fully below.

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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.

Key Factors Affecting Results of Operations and Financial Condition

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows have continued to be materially affected by costs the Utility has incurred to improve the safety and reliability of its natural gas operations, as well as by costs related to the ongoing regulatory proceedings, investigations, and civil lawsuits that commenced following the rupture of one of the Utility’s natural gas transmission pipelines in San Bruno, California on September 9, 2010 (the “San Bruno accident”).  Through December 31, 2012, PG&E Corporation and the Utility have incurred cumulative charges of approximately $1.83 billion related to the San Bruno accident and natural gas matters.  For 2012, this amount includes pipeline-related expenses of $477 million and capital expenditures of $353 million that will not be recoverable through rates.  (See “CPUC Gas Safety Rulemaking Proceeding” below.) These matters and a number of other factors will continue to have a material negative impact on PG&E Corporation’s and the Utility’s future results of operations, financial condition, and cash flows.

·   The Outcome of Matters Related to the Utility’s Natural Gas System.  The Utility forecasts that it will incur total pipeline-related costs ranging from $400 million to $500 million in 2013 that will not be recoverable through rates.  These amounts include costs to perform work under the Utility’s pipeline safety enhancement plan that were disallowed by the CPUC, as well as costs related to the Utility’s multi-year effort to identify and remove encroachments from transmission pipeline rights-of-way; costs associated with the integrity of transmission pipelines and other gas-related work; and legal and regulatory expenses.  (See “Operating and Maintenance” below.)  In addition, PG&E Corporation and the Utility believe that the CPUC will impose penalties on the Utility of at least $200 million in connection with three pending CPUC investigations and other potential enforcement matters. The ultimate amount of penalties could be materially higher and the Utility may also incur costs to implement any remedial actions the CPUC may order the Utility to perform.  (See “Pending CPUC Investigations and  Enforcement Matters” below.)  An ongoing investigation of the San Bruno accident by federal, state, and local authorities may result in the imposition of civil or criminal penalties on the Utility.  (See “Criminal Investigation” below.)  Finally, PG&E Corporation and the Utility believe it is reasonably possible that they may incur additional charges of up to $145 million for estimated third-party claims related to the San Bruno accident.  (See “Third-Party Claims” below.)

·   Authorized Rate of Return, Capital Structure, and Financing Needs.  The CPUC has authorized the Utility’s capital structure through 2015 for the Utility’s electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base, consisting of 52% common equity and 48% debt and preferred stock.  The CPUC also authorized the Utility to earn a ROE of 10.40% beginning January 1, 2013, compared to the 11.35% previously authorized.  (See “2013 Cost of Capital Proceeding” below.)  In addition, the FERC has ordered the Utility to revise its requested revenue requirements and rates in its pending TO rate case to reflect a 9.1% ROE on electric transmission assets, rather than the 11.5% ROE originally requested by the Utility.  (See “FERC Transmission Owner Rate Case” below.)  PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure.  The Utility has incurred significant expenses that are not recoverable through rates, which has increased the Utility’s equity needs.  In 2012, PG&E Corporation made equity contributions to the Utility of $885 million, which were funded primarily through common stock issuances that had a material dilutive effect on PG&E Corporation’s earnings per common share.  PG&E Corporation forecasts that it will issue additional common stock of approximately $1 billion in 2013 to fund the Utility’s equity needs.  Issuances that are used to fund the Utility’s equity needs that are attributable to unrecoverable costs and penalties will have an additional dilutive effect.  The Utility’s debt and equity financing needs also will be affected by other factors, including the timing and amount of the Utility’s capital expenditures, operating expenses, and collateral requirements associated with price risk management activities.  The Utility forecasts that capital spending will total approximately $5.1 billion in 2013, including capital projects related to its pipeline safety enhancement plan.  PG&E Corporation’s and the Utility’s ability to access the capital markets and the terms and rates of future financings could be affected by changes in their respective credit ratings, the outcome of natural gas matters, general economic and market conditions, and other factors.  (See “Liquidity and Financial Resources” below.)

4

·   The Timing and Outcome of Ratemaking Proceedings.  The Utility’s financial results are affected by the timing and outcome of ratemaking proceedings.  The CPUC issued decisions in 2011 that determined the majority of the Utility’s base revenue requirements through 2013.  In November 2012, the Utility filed its 2014 GRC application with the CPUC to request that the CPUC determine the amount of revenue requirements the Utility is authorized to collect through rates for its electric generation operations and electric and natural gas distribution from 2014 through 2016.  The Utility has requested that the CPUC increase the Utility’s base revenues for 2014 by $1.28 billion over the comparable revenues for 2013 that were previously authorized.  (See “2014 General Rate Case” below.)  The FERC is expected to determine in the pending TO rate case the amount of electric transmission revenues the Utility can recover beginning in May 2013.  (See “FERC Transmission Owner Rate Case” below.)  In addition, in late 2013, the Utility expects to file an application with the CPUC to initiate the Utility’s 2015 GT&S rate case in which the CPUC will determine the rates, and terms and conditions of the Utility’s gas transmission and storage services beginning January 1, 2015.  The outcome of these ratemaking proceedings can be affected by many factors, including general economic conditions, the level of customer rates, regulatory policies, and political considerations.

·   The Ability of the Utility to Control Operating Costs and Capital Expenditures.  Rates are primarily set based on forecasts and assumptions about the amount of operating costs and capital expenditures the Utility will incur in future periods.  PG&E Corporation’s and the Utility’s net income is negatively affected when the revenues provided by rates are not sufficient for the Utility to recover the costs it actually incurs.  In 2012, in addition to the non-recoverable costs related to the Utility’s natural gas system described above, the Utility incurred costs of $255 million to improve the safety and reliability of its electric and natural gas operations that it will not recover in rates.  The Utility forecasts that it will incur approximately $250 million to make additional incremental improvements in 2013 that it will not recover in rates.  (See “Operating and Maintenance” below.)  In addition, 2013 net income will be negatively affected by costs related to capital expenditures that the Utility forecasts will exceed authorized levels.  Any future increase in the Utility’s environmental-related liabilities that are not recoverable through rates, such as costs associated with its natural gas compressor station located in Hinkley, California, also will negatively affect PG&E Corporation’s and the Utility’s net income.  For 2012, the Utility recorded total charges to net income of $127 million for environmental remediation related to the Hinkley site.  (See “Environmental Matters” below.)  Other differences between the amount or timing of the Utility’s actual costs and forecasted or authorized amounts may also affect the Utility’s ability to earn its authorized ROE.

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Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for 2012

The following table is a summary reconciliation of the key changes, after-tax, in PG&E Corporation’s income available for common shareholders and earnings per common share for the year ended December 31, 2012:

				Earnings Per
				Common Share
(in millions, except per share amounts)	Earnings			(Diluted)
Income Available for Common Shareholders - 2011	$	844		$	2.10
Increase in rate base earnings		80			0.19
Natural gas matters (1)		32			0.15
Storm and outage expenses		28			0.06
Litigation and regulatory matters		27			0.06
Gas transmission revenues		15			0.04
Environmental-related costs		11			0.03
Planned incremental work		(151	)		(0.36	)
Employee operational performance incentive		(33	)		(0.08	)
Energy efficiency incentive		(3	)		(0.01	)
Increase in shares outstanding (2)		-			(0.19	)
Other		(34	)		(0.07	)
Income Available for Common Shareholders - 2012	$	816		$	1.92

(1) The Utility incurred charges related to natural gas matters of $812 million and $739 million, pre-tax, for 2012 and 2011, respectively.  The amount shown above represents the favorable tax impact attributable to the lower amount of non-deductible penalties recorded in 2012 of $17 million, as compared to $200 million recorded in 2011.

 (2) Represents the impact of a higher number of shares outstanding at December 31, 2012, compared to the number of shares outstanding at December 31, 2011.  PG&E Corporation issues shares to fund its equity contributions to the Utility to maintain the Utility’s capital structure and fund operations, including expenses related to natural gas matters.  This has no dollar impact on earnings.

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This 2012 Annual Report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  These statements reflect management’s judgment and opinions which 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 losses associated with various investigations; estimated losses and insurance recoveries associated with the civil litigation arising from the San Bruno accident; forecasts of costs the Utility will incur to make safety and reliability improvements, including costs to perform work under the pipeline safety enhancement plan, that the Utility will not recover through rates; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to environmental remediation, tax, litigation, third-party claims, and other liabilities; and the level of future equity or debt issuances.  These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “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 timing and terms of the resolution of pending investigations and enforcement matters related to the Utility’s natural gas system operating practices and the San Bruno accident, including the ultimate amount of penalties the Utility will be required to pay, the cost of any remedial actions the Utility may be ordered to perform, and whether the resolution is reached through settlement negotiations, or a fully litigated proceeding; the ultimate amount of third-party claims associated with the San Bruno accident and the timing and amount of related insurance recoveries; the ultimate amount of punitive damages, if any, the Utility may incur related to third-party claims; and the ultimate amount of civil or criminal penalties, if any, the Utility may incur related to the criminal investigation;

·   the outcomes of current ratemaking proceedings, such as the 2014 GRC and the pending TO rate case;  the outcome of future ratemaking and regulatory proceedings, such as the 2015 GT&S rate case, and the CPUC’s natural gas rulemaking proceeding in which the CPUC will consider the Utility’s proposed scope, timing, and cost recovery mechanisms that will apply to the second phase of the pipeline safety enhancement plan; and the outcomes of other ratemaking and regulatory proceedings;

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·   the ultimate amount of costs the Utility incurs in the future that are not recovered through rates, including costs to perform work under the pipeline safety enhancement plan, to identify and remove encroachments from transmission pipeline easements, and to perform incremental work to improve the safety and reliability of electric and natural gas operations;

·   the outcome of future investigations or proceedings that may be commenced by the CPUC or other regulatory authorities relating to the Utility’s compliance with laws, rules, regulations, or orders applicable to the operation, inspection, and maintenance of its electric and gas facilities;

·   whether PG&E Corporation and the Utility are able to repair the reputational harm that they have suffered, and may suffer in the future, due to the negative publicity surrounding the San Bruno accident, the related civil litigation, and the pending investigations, including any charge or finding of criminal liability;

·   the level of equity contributions that PG&E Corporation must make to the Utility to enable the Utility to maintain its authorized capital structure as the Utility incurs charges and costs, including costs associated with natural gas matters and penalties imposed in connection with the pending investigations, that are not recoverable through rates or insurance;

·   the impact of environmental remediation laws, regulations, and orders; the ultimate amount of costs incurred to discharge the Utility’s known and unknown remediation obligations; the extent to which the Utility is able to recover compliance and remediation costs from third parties or through rates or insurance; and the ultimate amount of costs the Utility incurs in connection with environmental remediation liabilities that are not recoverable through rates or insurance, such as the remediation costs associated with the Utility’s natural gas compressor station site located near Hinkley, California;

·   the impact of new legislation or NRC regulations, recommendations, policies, decisions, or orders relating to the operations, seismic design, security, safety, or decommissioning of nuclear facilities, including the Utility’s Diablo Canyon nuclear power plant (“Diablo Canyon”), or relating to the storage of spent nuclear fuel, cooling water intake, or other issues; and the ability of the Utility to relicense the Diablo Canyon units;

·   the impact of weather-related conditions or events (such as storms, tornadoes, floods, drought, solar or electromagnetic events, and wildland and other fires), natural disasters (such as earthquakes, tsunamis, and pandemics), and other events (such as explosions, fires, accidents, mechanical breakdowns, equipment failures, human errors, and labor disruptions), as well as acts of terrorism, war, or vandalism, including cyber-attacks, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or 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; and subject the Utility to third-party liability for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory penalties on the Utility;

·   the impact of environmental laws and regulations aimed at the reduction of carbon dioxide and other greenhouse gases (“GHG”s), and whether the Utility is able to recover associated compliance costs, including the cost of emission allowances and offsets, that the Utility may incur under cap-and-trade regulations;

·   changes in customer demand for electricity (“load”) and natural gas resulting from unanticipated population growth or decline in the Utility’s service area, general and regional economic and financial market conditions, the extent of municipalization of the Utility’s electric distribution facilities, changing levels of “direct access” customers who procure electricity from alternative energy providers, changing levels of customers who purchase electricity from governmental bodies that act as “community choice aggregators,” and the development of alternative energy technologies including self-generation and distributed generation technologies;

·   the adequacy and price of electricity, natural gas, and nuclear fuel supplies; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its energy commodity costs through rates;

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·   whether the Utility’s information technology, operating systems and networks, including the advanced metering system infrastructure, customer billing, financial, and other systems, can continue to function accurately while meeting regulatory requirements; whether the Utility is able to protect its operating systems and networks from damage, disruption, or failure caused by cyber-attacks, computer viruses, or other hazards; whether the Utility’s security measures are sufficient to protect  customer, vendor, and financial data contained in such systems and networks; and whether the Utility can continue to rely on third-party vendors and contractors that maintain and support some of the Utility’s operating systems;

·   the extent to which costs incurred in connection with third-party claims or litigation are not recoverable through insurance, rates, or from other third parties;

·   the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms;

·   the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies, including 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 whether the outcome of proceedings and investigations relating to the Utility’s natural gas operations affects the Utility’s ability to make distributions to PG&E Corporation in the form of dividends or share repurchases; and, in turn, PG&E Corporation’s ability to pay dividends;

·   the outcome of federal or state tax audits and the impact of any changes in federal or state tax laws, policies, or regulations; and

·   the impact of changes in generally accepted accounting principles, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application.

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, results of operations, and cash flows, see “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 2012, 2011, and 2010:

	Year ended December 31,
(in millions)	2012			2011			2010
Utility
Electric operating revenues	$	12,014		$	11,601		$	10,644
Natural gas operating revenues		3,021			3,350			3,196
Total operating revenues		15,035			14,951			13,840
Cost of electricity		4,162			4,016			3,898
Cost of natural gas		861			1,317			1,291
Operating and maintenance		6,045			5,459			4,432
Depreciation, amortization, and decommissioning		2,272			2,215			1,905
Total operating expenses		13,340			13,007			11,526
Operating income		1,695			1,944			2,314
Interest income		6			5			9
Interest expense		(680	)		(677	)		(650	)
Other income, net		88			53			22
Income before income taxes		1,109			1,325			1,695
Income tax provision		298			480			574
Net income		811			845			1,121
Preferred stock dividend requirement		14			14			14
Income Available for Common Stock	$	797		$	831		$	1,107
PG&E Corporation, Eliminations, and Other (1)
Operating revenues	$	5		$	5		$	1
Operating expenses		7			7			7
Operating loss		(2	)		(2	)		(6	)
Interest income		1			2			-
Interest expense		(23	)		(23	)		(34	)
Other (expense) income, net		(18	)		(4	)		5
Loss before income taxes		(42	)		(27	)		(35	)
Income tax benefit		(61	)		(40	)		(27	)
Net income (loss)	$	19		$	13		$	(8	)
Consolidated Total
Operating revenues	$	15,040		$	14,956		$	13,841
Operating expenses		13,347			13,014			11,533
Operating income		1,693			1,942			2,308
Interest income		7			7			9
Interest expense		(703	)		(700	)		(684	)
Other income, net		70			49			27
Income before income taxes		1,067			1,298			1,660
Income tax provision		237			440			547
Net income		830			858			1,113
Preferred stock dividend requirement of subsidiary		14			14			14
Income Available for Common Shareholders	$	816		$	844		$	1,099

9

The following presents the Utility’s operating results for 2012, 2011, and 2010.

Electric Operating Revenues

The Utility’s electric operating revenues consist of amounts charged to customers for electricity generation, transmission and distribution services, as well as amounts charged to customers to recover the cost of electricity procurement and the cost of public purpose, energy efficiency, and demand response programs.

The following table provides a summary of the Utility’s total electric operating revenues:

(in millions)	2012		2011		2010
Revenues excluding passed-through costs	$	6,280	$	6,150	$	5,473
Revenues for recovery of passed-through costs		5,734		5,451		5,171
Total electric operating revenues	$	12,014	$	11,601	$	10,644

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $413 million, or 4%, in 2012 compared to 2011.  Revenues intended to recover costs that are passed through to customers and do not impact net income increased by $283 million, primarily due to an increase in the cost of electricity (See “Cost of Electricity” below), the cost of public purpose programs, and pension contributions.  Electric operating revenues, excluding revenues intended to recover costs that are passed through to customers, increased by $130 million, primarily due to an increase in base revenues as authorized in the 2011 GRC and in the TO rate case.

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $957 million, or 9%, in 2011 compared to 2010.  Revenues intended to recover costs that are passed through to customers and do not impact net income increased by $280 million, primarily due to increases in the cost of electricity (see “Cost of Electricity” below), the cost of public purpose programs, and pension contributions.  Electric operating revenues, excluding revenues intended to recover costs that are passed through to customers, increased by $677 million.  The increase is primarily due to additional base revenues that were authorized by the CPUC in the 2011 GRC and for various separately funded projects, and authorized by the FERC in the TO rate case that became effective March 1, 2011.

The Utility’s future electric operating revenues, excluding revenues intended to recover costs that are passed through to customers, are expected to increase in 2013 as authorized by the CPUC in the 2011 GRC.  This increase to future revenues will be offset by the lower revenues authorized by the CPUC in the 2013 Cost of Capital proceeding.  (See “Regulatory Matters” below.)  Additionally, the Utility’s future electric operating revenues are expected to be impacted by revenues authorized by the FERC in the TO rate case (these increased revenues are expected to become effective on May 1, 2013) and by the CPUC in the 2014 GRC, which was filed on November 14, 2012.  Future electric operating revenues will also be impacted by the cost of electricity and other revenues intended to recover costs that are passed through to customers.

Cost of Electricity

The Utility’s cost of electricity includes the costs of power purchased from third parties, transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, and realized gains and losses on price risk management activities.  (See Note 10 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 and electric transmission and distribution system, which are included in operating and maintenance expense in the Consolidated Statements of Income.

The following table provides a summary of the Utility’s cost of electricity and the total amount and average cost of purchased power:

(in millions)	2012		2011		2010
Cost of purchased power	$	3,873	$	3,719	$	3,647
Fuel used in own generation facilities		289		297		251
Total cost of electricity	$	4,162	$	4,016	$	3,898
Average cost of purchased power per kWh (1)	$	0.079	$	0.089	$	0.081
Total purchased power (in millions of kWh)		48,933		41,958		44,837
(1) Kilowatt-hour

10

The Utility’s total cost of electricity increased by $146 million, or 4%, in 2012 compared to 2011, primarily due to an increase in the volume of power purchased as customer demand increased and higher costs to purchase renewable energy.  The higher cost of electricity was partially offset by the decrease in the average cost of purchased power which reflected lower spot prices.   The volume of power the Utility purchases is driven by customer demand, the availability of the Utility’s own generation facilities, and the cost effectiveness of each source of electricity.

The Utility’s total cost of electricity increased by $118 million, or 3%, in 2011 compared to 2010.  The increase was due to an increase in the average cost of purchased power resulting from increased renewable energy deliveries and higher transmission costs.

Various factors will affect the Utility’s future cost of electricity, including the market prices for electricity and natural gas, the availability of Utility-owned generation, and changes in customer demand.  Additionally, the cost of electricity is expected to be impacted by 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’s future cost of electricity also will be affected by legislation and rules applicable to GHG emissions.  (See “Environmental Matters” below.)

Natural Gas Operating Revenues

The Utility’s natural gas operating revenues consist of amounts charged for transportation, distribution, and storage services, as well as amounts charged to customers to recover the cost of natural gas procurement and public purpose programs.

The following table provides a summary of the Utility’s natural gas operating revenues:

(in millions)	2012		2011		2010
Revenues excluding passed-through costs	$	1,772	$	1,696	$	1,627
Revenues for recovery of passed-through costs		1,249		1,654		1,569
Total natural gas operating revenues	$	3,021	$	3,350	$	3,196

The Utility’s natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, decreased by $329 million, or 10%, in 2012 compared to 2011.  Revenues intended to recover costs that are passed through to customers and do not impact net income decreased by $405 million primarily due to a decrease in the cost of natural gas.  Natural gas operating revenues, excluding revenues intended to recover costs that are passed through to customers, increased by $76 million, primarily due to an increase in base revenues as authorized in the 2011 GT&S rate case and the 2011 GRC and increases in natural gas storage revenues.

The Utility’s natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $154 million, or 5%, in 2011 compared to 2010.  Revenues intended to recover costs that are passed through to customers and do not impact net income increased by $85 million, primarily due to an increase in the costs of public purpose programs and pension contributions.  Natural gas operating revenues, excluding revenues intended to recover costs that are passed through to customers, increased by $69 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 2011 and less gas was transported from storage due to the milder weather that prevailed in 2011 compared to 2010.  As result, the Utility was unable to accept more gas for storage.)

The Utility’s operating revenues for natural gas transmission services are expected to increase for 2013 and 2014 as authorized by the CPUC in the 2011 GT&S rate case and will also be impacted by revenues authorized by the CPUC in the 2014 GRC.  The Utility’s revenues for natural gas distribution services in 2013, excluding revenues intended to recover passed-through costs, will also reflect revenue increases authorized by the CPUC in the 2011 GRC.  These increases to future revenues will be offset by the lower revenues authorized by the CPUC in the 2013 Cost of Capital proceeding.  (See “Regulatory Matters” below.)  Additionally, the Utility’s future operating revenues will reflect those revenues authorized by the CPUC under the Utility’s pipeline safety enhancement plan.  (See “Natural Gas Matters” below.)  The Utility’s future gas operating revenues also will be impacted by the cost of natural gas, natural gas throughput volume, and other factors.

11

Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of procurement, storage, transportation of natural gas and realized gains and losses on price risk management activities.  (See Note 10 of the Notes to the Consolidated Financial Statements.)  The Utility’s cost of natural gas is passed through to customers.  The Utility’s cost of natural gas excludes the cost of operating the Utility’s gas transmission and distribution system, which is included in operating and maintenance expense in the Consolidated Statements of Income.

The following table provides a summary of the Utility’s cost of natural gas:

(in millions)	2012		2011		2010
Cost of natural gas sold	$	676	$	1,136	$	1,119
Transportation cost of natural gas sold		185		181		172
Total cost of natural gas	$	861	$	1,317	$	1,291
Average cost per Mcf of natural gas sold	$	2.91	$	4.49	$	4.69
Total natural gas sold (in millions of Mcf) (1)		232		253		249
(1) One thousand cubic feet

The Utility’s total cost of natural gas decreased by $456 million, or 35%, in 2012 compared to 2011, primarily due to a lower average market price of natural gas during 2012.

The Utility’s total cost of natural gas increased by $26 million, or 2%, in 2011 compared to 2010, primarily due to the absence of a $49 million refund the Utility received in 2010 to be passed through to customers as part of a litigation settlement.

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.

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.  The Utility’s ability to earn its authorized rate of return depends in part on its ability to manage its expenses and to achieve operational and cost efficiencies.

The Utility’s operating and maintenance expenses (including costs passed through to customers) increased by $586 million, or 11%, from $5,459 million in 2011 to $6,045 million in 2012.  Excluding costs passed through to customers, operating and maintenance expense increased $488 million, primarily due to costs incurred to improve the safety and reliability of electric and natural gas operations that were $255 million higher than amounts assumed under the 2011 rate cases.  The remaining increase was attributable to $73 million of net costs associated with natural gas matters (see table below), $56 million of employee operational performance incentive, and $26 million of planned maintenance costs associated with the Gateway Generating Station.  These costs were partially offset by a $25 million decrease in legal and regulatory matters, including penalties associated with the Rancho Cordova accident in 2011.  Costs that are passed through to customers and do not impact net income increased by $98 million, primarily due to costs associated with advanced electric and gas meters that use SmartMeterTM technology and pension contributions.

The Utility’s operating and maintenance expenses (including costs passed through to customers) increased by $1,027 million, or 23%, from $4,432 million in 2010 to $5,459 million in 2011.  Excluding costs passed through to customers, operating and maintenance expenses increased by $817 million in 2011 compared to 2010, primarily due to a $456 million increase in costs for natural gas matters.  (See table below.)  The remaining increase in operating and maintenance costs was attributable to a number of factors, including $122 million for estimated environmental remediation costs and other liabilities associated with Hinkley natural gas compressor site and approximately $82 million for labor and other maintenance-related costs, primarily associated with higher storm costs.  Additionally, legal and regulatory matters increased $32 million, including penalties associated with the Rancho Cordova accident.  Costs that are passed through to customers and do not impact net income increased by $210 million primarily due to pension expense, public purpose programs, and meter reading.

12

The following table provides a summary of the Utility’s costs associated with natural gas matters, included in operating and maintenance expenses:

(in millions)	2012			2011			2010		Total
Pipeline-related expenses	$	477		$	483		$	63	$	1,023
Disallowed capital expenditures		353			-			-		353
Accrued penalties		17			200			-		217
Third-party claims		80			155			220		455
Insurance recoveries		(185	)		(99	)		-		(284	)
Contribution to City of San Bruno		70			-			-		70
Total natural gas matters	$	812		$	739		$	283	$	1,834

The Utility incurred net costs of $812 million, $739 million, and $283 million during 2012, 2011 and 2010, respectively, in connection with natural gas matters that are not recoverable through rates.  These amounts primarily include pipeline-related expenses which consist of costs to validate safe operating pressures, conduct strength testing, and perform other work (including work within the scope of the Utility’s pipeline safety enhancement plan), as well as associated legal and regulatory costs.  In addition, a $353 million charge was recorded in 2012 for disallowed capital expenditures related to the Utility’s pipeline safety enhancement plan that are forecasted to exceed the CPUC’s authorized levels or that were specifically disallowed.  Also included above are estimated penalties related to the CPUC’s pending investigations and other potential enforcement matters, accruals for third-party claims related to the San Bruno accident, and a contribution to the City of San Bruno.  These costs were partially offset by insurance recoveries related to third-party claims.  (See “Natural Gas Matters” below.)

The Utility forecasts that it will incur total pipeline-related costs ranging from $400 million to $500 million in 2013 that will not be recoverable through rates.  These amounts include costs to perform work under the Utility’s pipeline safety enhancement plan that were disallowed by the CPUC.  These amounts also include emerging work related to the Utility’s multi-year effort to identify and remove encroachments (such as building structures and vegetation overgrowth) from transmission pipeline rights-of-way, as well as costs associated with the integrity of transmission pipelines and other gas-related work.  The Utility also expects it will continue to incur legal and regulatory expenses associated with its natural gas system. The Utility may incur costs to implement any remedial actions the CPUC may order the Utility to perform.  (See “Natural Gas Matters – Pending CPUC Investigations and Enforcement Matters” below.)

Future operating and maintenance expense will also continue to be affected by other costs associated with natural gas matters that are not recoverable through rates, including any additional charges for third-party claims arising from the San Bruno accident that are not recoverable through insurance, additional charges for civil or criminal penalties, or punitive damages, if any, that may be imposed on the Utility. (See “Natural Gas Matters” below.)

                The Utility forecasts that it will incur expenses in 2013 that are approximately $250  million higher than amounts assumed under the 2011 GRC and GT&S rate case as the Utility works to improve the safety and reliability of its electric and natural gas operations.

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 fuel-fired generation facilities and nuclear power facilities.  The Utility’s depreciation, amortization, and decommissioning expenses increased by $57 million, or 3%, in 2012 compared to 2011, primarily due to capital additions.

The Utility’s depreciation, amortization, and decommissioning expenses increased by $310 million, or 16%, in 2011 compared to 2010, primarily due to capital additions and an increase in depreciation rates as authorized by the 2011 GRC and 2011 GT&S rate cases.

The Utility’s depreciation expense for future periods is expected to be affected as a result of changes in capital expenditures and the implementation of new depreciation rates as authorized by the CPUC in future GRCs and GT&S rate cases.  Future TO rate cases authorized by the FERC will also have an impact on depreciation rates.

13

Interest Income and Interest Expense

There were no material changes to interest income and interest expense for 2012 compared to 2011 or for 2011 compared to 2010.

Other Income, Net

The Utility’s other income, net increased by $35 million, in 2012 compared to 2011.  The increase was primarily due to an increase in allowance for equity funds used during construction (“AFUDC”) as the average balance of construction work in progress was higher in 2012 as compared to 2011.

The Utility’s other income, net increased by $31 million, in 2011 compared to 2010 when the Utility incurred costs to support a California ballot initiative that appeared on the June 2010 ballot that were not recoverable in rates.  The increase was partially offset by a decrease in AFUDC as the average balance of construction work in progress was lower in 2011 compared to 2010.

Income Tax Provision

The Utility’s income tax provision decreased by $182 million, or 38%, in 2012 compared to 2011.  The effective tax rates were 27% and 36% for 2012 and 2011, respectively.  The effective tax rates for 2012 decreased compared to 2011, primarily due to lower non-tax deductible penalties related to natural gas matters, and higher state benefits received and deductions in 2012, including a benefit associated with a California research and development claim, with no comparable amount in 2011; a higher California tax deduction resulting from an accounting method change for repairs as compared to 2011; and a California tax benefit associated with shorter depreciable lives related to meters that use SmartMeterTM technology recorded in 2012 with no comparable amount in 2011.

The Utility’s income tax provision decreased by $94 million, or 16%, in 2011 compared to 2010.  The effective tax rates were 36% and 34% for 2011 and 2010, respectively.  The effective tax rate for 2011 increased as compared to 2010, mainly due to non- tax deductible penalties related to natural gas matters recorded in 2011, with no comparable penalties recorded in 2010, partially offset by a benefit associated with a loss carryback recorded in 2011 and the reversal of a deferred tax asset attributable to the Medicare Part D subsidy, which affected the tax provision balance in 2010, with no comparable effect in 2011.

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 2012, 2011, and 2010 were as follows:

	2012			2011			2010
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)		(3.0	)		1.6			1.0
Effect of regulatory treatment of fixed asset differences		(3.9	)		(4.2	)		(3.0	)
Tax credits		(0.6	)		(0.5	)		(0.4	)
Benefit of loss carryback		(0.4	)		(2.1	)		-
Non deductible penalties		0.5			6.3			0.2
Other, net		(0.8	)		0.1			1.1
Effective tax rate		26.8	%		36.2	%		33.9	%

14

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 outstanding senior notes, and is not allocated to affiliates.

There were no material changes to PG&E Corporation’s operating results in 2012 compared to 2011 and 2011 compared to 2010.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations and make distributions to PG&E Corporation 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, volatility in energy commodity costs, collateral requirements related to price risk management activities, the timing and amount of tax payments or refunds, and the timing and effect of regulatory decisions and long-term financings, among other factors.  The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances 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, 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.

PG&E Corporation’s and the Utility’s credit ratings may affect their access to the credit and capital markets and their respective financing costs in those markets.  Credit rating downgrades may increase the cost of short-term borrowing, including the Utility’s commercial paper and the costs associated with their respective credit facilities, and long-term debt.

PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds.  The following table summarizes PG&E Corporation’s and the Utility’s cash positions:

	December 31,
(in millions)	2012			2011
PG&E Corporation		$	207		$	209
Utility			194			304
Total consolidated cash and cash equivalents		$	401		$	513

In addition to these cash and cash equivalents, PG&E Corporation and the Utility hold restricted cash that primarily consists of cash held in escrow pending the resolution of the remaining disputed claims that were filed in the Utility’s reorganization proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”).  (See Note 13 of the Notes to the Consolidated Financial Statements.)

15

Revolving Credit Facilities and Commercial Paper Program

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and the Utility’s commercial paper program at December 31, 2012:

					Letters of
	Termination	Facility			Credit				Commercial			Facility
	Date	Limit			Outstanding		Borrowings		Paper			Availability
(in millions)
PG&E Corporation	May 2016	$	300	(1)	$	-	$	120	$	-		$	180
Utility	May 2016		3,000	(2)		266		-		370	(3)		2,364	(3)
Total revolving
credit facilities		$	3,300		$	266	$	120	$	370		$	2,544

(1) Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.

(2) Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.

(3) The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.

For 2012, the average outstanding borrowings under PG&E Corporation’s revolving credit facility were $21 million and the maximum outstanding balance during the year was $120 million.  For 2012, the Utility’s average outstanding commercial paper balance was $665 million and the maximum outstanding balance during the year was $1.4 billion.  The Utility did not borrow under its credit facility in 2012.

The revolving credit facilities include usual and customary covenants for revolving credit facilities of this type, including covenants limiting liens to those permitted under PG&E Corporation’s and the Utility’s senior note indentures, mergers, sales of all or substantially all of PG&E Corporation’s and the Utility’s assets, and other fundamental changes.  In addition, the revolving credit facilities require that PG&E Corporation and 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.  PG&E Corporation’s revolving credit facility agreement also requires that PG&E Corporation 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, 2012, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

See Note 4 of the Notes to the Consolidated Financial Statements for additional information about the credit facilities and the Utility’s commercial paper program.

2012 Financings

Utility

The following table summarizes long-term debt issuances in 2012:

(in millions)	Issue Date	Amount
Senior Notes
4.45%, due 2042	April 16	$	400
2.45%, due 2022	August 16		400
3.75%, due 2042	August 16		350
Total debt issuances in 2012		$	1,150

The net proceeds from the issuance of Utility senior notes in 2012 were used to repay a portion of outstanding commercial paper, and for general corporate purposes.

The Utility also received cash contributions of $885 million from PG&E Corporation during 2012 to ensure that the Utility had adequate capital to maintain the 52% common equity ratio authorized by the CPUC.

16

PG&E Corporation

In November 2011, PG&E Corporation entered into an Equity Distribution Agreement providing for the sale of 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.  For 2012, PG&E Corporation sold 5,446,760 shares of its common stock under the Equity Distribution Agreement for cash proceeds of $234 million, net of fees and commissions paid of $2 million.  The proceeds from these sales were used for general corporate purposes, including the infusion of equity into the Utility.  As of December 31, 2012, PG&E Corporation had the ability to issue an additional $64 million of its common stock under the November Equity Distribution Agreement.

In March 2012, PG&E Corporation sold 5,900,000 shares of its common stock in an underwritten public offering for cash proceeds of $254 million, net of fees and commissions.  In addition, during 2012, PG&E Corporation issued 6,803,101 shares of common stock under its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and its share-based compensation plans, generating $263 million of cash.

Future Financing Needs

The amount and timing of the Utility’s future debt financings and equity needs will depend on various factors, including:

·   the amount of cash internally generated through normal business operations;

·   the timing and amount of forecasted capital expenditures;

·   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 (see “Natural Gas Matters” below);

·   the timing and amount of penalties imposed on the Utility in connection with the pending investigations and other potential enforcement matters related to the San Bruno accident and the Utility’s natural gas operations (see “Natural Gas Matters” below);

·   the timing and amount of pipeline-related expenses and other expenses to improve the safety and reliability of the Utility’s electric and natural gas operations that are not recoverable through rates (see “Operating and Maintenance” above);

·   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 (see Note 13 of the Notes to the Consolidated Financial Statements);

·   the amount of future tax payments; and

·   the conditions in the capital markets, and other factors.

PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure.  In December 2012, the CPUC issued a final decision authorizing the Utility to maintain a capital structure consisting of 52% equity, 47% long-term debt and 1% preferred stock, beginning on January 1, 2013.  The decision also reduced the authorized ROE from 11.35% to 10.40%.  (See the “2013 Cost of Capital Proceeding” discussion in “Regulatory Matters” below.)  The Utility’s future equity needs will continue to be affected by costs that are not recoverable through rates, including costs related to natural gas matters.  Further, given the Utility’s significant ongoing capital expenditures, it will continue to need equity contributions from PG&E Corporation to maintain its authorized capital structure.

PG&E Corporation’s equity contributions to the Utility are funded primarily through common stock issuances.  PG&E Corporation also may use draws under its revolving credit facility to occasionally fund equity contributions on an interim basis.  Additional common stock issued by PG&E Corporation in the future to fund further equity contributions to the Utility could have a material dilutive effect on PG&E Corporation’s earnings per common share.  

17

Dividends

The Board of Directors of PG&E Corporation and the Utility have each adopted a common stock dividend policy that is 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.

Each Board of Directors retains authority to change the common stock dividend rate 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.  In addition, before declaring a dividend, 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.  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 Board of Directors of PG&E Corporation declared dividends of $0.455 per share for each of the quarters of 2012, for an annual dividend of $1.82 per share.

The following table summarizes PG&E Corporation’s and the Utility’s dividends paid:

(in millions)	2012		2011		2010
PG&E Corporation:
Common stock dividends paid	$	746	$	704	$	662
Common stock dividends reinvested in Dividend Reinvestment
and Stock Purchase Plan		22		24		18
Utility:
Common stock dividends paid	$	716	$	716	$	716
Preferred stock dividends paid		14		14		14

In December 2012, the Board of Directors of PG&E Corporation declared quarterly dividends of $0.455 per share, totaling $196 million, of which $191 million was paid on January 15, 2013 to shareholders of record on December 31, 2012.  The remaining $5 million was reinvested under the Dividend Reinvestment and Stock Purchase Plan.

In December 2012, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on February 15, 2013, to shareholders of record on January 31, 2013.

As the Utility focuses on improving the safety and reliability of its natural gas and electric operations, and subject to the outcome of the matters described under “Natural Gas Matters” below, PG&E Corporation expects that its Board will continue to maintain the current quarterly common stock dividend.

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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 2012, 2011, and 2010 were as follows:

(in millions)	2012			2011			2010
Net income	$	811		$	845		$	1,121
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, amortization, and decommissioning		2,272			2,215			1,905
Allowance for equity funds used during construction		(107	)		(87	)		(110	)
Deferred income taxes and tax credits, net		684			582			762
Disallowed capital expenditures		353			-			36
Other		236			289			221
Effect of changes in operating assets and liabilities:
Accounts receivable		(40	)		(227	)		(105	)
Inventories		(24	)		(63	)		(43	)
Accounts payable		(26	)		51			109
Income taxes receivable/payable		(50	)		(192	)		(58	)
Other current assets and liabilities		272			36			123
Regulatory assets, liabilities, and balancing accounts, net		291			(100	)		(394	)
Other noncurrent assets and liabilities		256			414			(331	)
Net cash provided by operating activities	$	4,928		$	3,763		$	3,236

During 2012, net cash provided by operating activities increased by $1,165 million compared to 2011.  This increase was primarily due to a decrease of $352 million in net collateral paid by the Utility related to price risk management activities, a $353 million disallowance for capital expenditures incurred in connection with its pipeline safety enhancement plan, a receipt of $250 million, net of legal fees, from the U.S. Treasury related to spent nuclear fuel costs, and a decrease in tax payments of $224 million.  The remaining changes in cash flows from operating activities consisted of fluctuations in activities within the normal course of business such as the timing and amount of customer billings and collections.

During 2011, net cash provided by operating activities increased $527 million compared to 2010 primarily due to a decrease of $214 million in net collateral paid by the Utility related to price risk management activities.  This increase also reflects a decrease in tax payments of $121 million in 2011 compared to 2010.  The remaining changes in cash flows from operating activities consisted of fluctuations in activities within the normal course of business such as collateral and the timing and amount of customer billings and collections.

Future cash flow from operating activities will be affected by the timing and amount of payments to be made to third parties in connection with the San Bruno accident, including related insurance recoveries; the timing and amount of penalties that may be assessed, as well as any remedial actions the CPUC may order the Utility to perform; and the anticipated higher operating and maintenance costs associated with the Utility’s natural gas and electric operations, among other factors.  (See “Operating and Maintenance” above and “Natural Gas Matters” below.)

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Investing Activities

The Utility’s investing activities primarily consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers.  The amount and timing of the Utility’s capital expenditures is affected by many factors such as 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 which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments.  The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.

The Utility’s cash flows from investing activities for 2012, 2011, and 2010 were as follows:

(in millions)	2012			2011			2010
Capital expenditures	$	(4,624	)	$	(4,038	)	$	(3,802	)
Decrease in restricted cash		50			200			66
Proceeds from sales and maturities of nuclear decommissioning trust investments		1,133			1,928			1,405
Purchases of nuclear decommissioning trust investments		(1,189	)		(1,963	)		(1,456	)
Other		16			14			19
Net cash used in investing activities	$	(4,614	)	$	(3,859	)	$	(3,768	)

Net cash used in investing activities increased by $755 million in 2012 compared to 2011.  This increase was primarily due to an increase of $586 million in capital expenditures and a reduction in restricted cash released for resolved Chapter 11 disputed claims of $150 million.

Net cash used in investing activities increased by $91 million in 2011 compared to 2010, primarily due to an increase in capital expenditures of $236 million as compared to 2010.  This increase was partially offset by a decrease of $134 million in restricted cash that was primarily due to releases from escrow for resolved Chapter 11 disputed claims in 2011, with few similar releases in 2010.

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 2012, 2011, and 2010 were as follows:

(in millions)	2012			2011			2010
Borrowings under revolving credit facilities	$	-		$	208		$	400
Repayments under revolving credit facilities		-			(208	)		(400	)
Net issuances (repayments) of commercial paper, net of discount of $3 in 2012, $4 in 2011, and $3 in 2010		(1,021	)		782			267
Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2011 and 2010		-			250			249
Proceeds from issuance of long-term debt, net of premium, discount, and
issuance costs of $13 in 2012, $8 in 2011, and $23 in 2010		1,137			792			1,327
Short-term debt matured		(250	)		(250	)		(500	)
Long-term debt matured or repurchased		(50	)		(700	)		(95	)
Energy recovery bonds matured		(423	)		(404	)		(386	)
Preferred stock dividends paid		(14	)		(14	)		(14	)
Common stock dividends paid		(716	)		(716	)		(716	)
Equity contribution		885			555			190
Other		28			54			(73	)
Net cash provided by (used in) financing activities	$	(424	)	$	349		$	249

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In 2012, net cash provided by financing activities decreased by $773 million compared to the same period in 2011.  In 2011, net cash provided by financing activities increased by $100  million compared to 2010.  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 maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

PG&E Corporation

As of December 31, 2012, 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 has agreed to provide lease payments and investment contributions of up to $396 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies.  PG&E Corporation’s financial exposure from these arrangements is generally limited to its lease payments and investment contributions to these companies.  As of December 31, 2012, PG&E Corporation had made total payments of $361 million under these tax equity agreements and received $228 million in benefits and customer payments.  Lease payments, investment contributions, benefits, and customer payments received are included in cash flows from operating and investing activities 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, 2012, 2011, and 2010: dividend payments, common stock issuances, borrowings and repayments under the revolving credit facility in 2012 and 2011, and transactions between PG&E Corporation and the Utility.

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CONTRACTUAL COMMITMENTS

	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	$ 1,035	$ 2,148	$ 1,824	$ 17,305		$ 22,312
Variable rate obligations	2	8	941	153		1,104
Purchase obligations (2):
Power purchase agreements :
Qualifying facilities (“QF”)	892	1,641	1,108	2,238		5,879
Renewable contracts (other than QF)	1,356	3,881	4,107	30,958		40,302
Other power purchase agreements	846	1,326	1,223	3,322		6,717
Natural gas supply, transportation and storage	707	400	260	865		2,232
Nuclear fuel agreements	113	322	295	878		1,608
Pension and other benefits (3)	455	796	796	398	(6)	2,445
Capital lease obligations (4)	35	51	40	20		146
Operating leases (4)	42	69	55	206		372
Preferred dividends (5)	14	28	28	-		70
PG&E Corporation
Long-term debt (1):
Fixed rate obligations	20	355	-	-		375
(1) Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at December 31, 2012 and outstanding principal for each instrument with the terms ending at each instrument’s maturity. Variable rate obligations consist of pollution control bonds, due in 2016 and 2026 and related loans and are backed by letters of credit that expire on May 31, 2016. (See Note 4 of the Notes to the Consolidated Financial Statements.)
(2) This table includes power purchase agreements that have been approved by the CPUC and have completed major milestones for construction. (See Note 15 of the Notes to the Consolidated Financial Statements.)
(3) 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. (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 and other benefit 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, 2012, the Utility was committed to spending approximately $277 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 $86 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, resulting in the capital expenditures being recoverable from customers.

The contractual commitments table above also excludes potential payments associated with unrecognized tax positions.  Due to the uncertainty surrounding tax audits, PG&E Corporation and the Utility cannot make reliable estimates of the amounts and periods 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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CAPITAL EXPENDITURES

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 growth.  Most of the Utility’s revenue requirements to recover forecasted capital expenditures are authorized in the GRC, TO, and GT&S rate cases.  (See “2014 General Rate Case” below.) The Utility also collects additional revenue requirements to recover capital expenditures related to projects that have been specifically authorized by the CPUC, such as new power plants, gas or electric distribution projects, and the SmartMeterTM advanced metering infrastructure.

The Utility’s capital expenditures for property, plant, and equipment totaled $4.8 billion in 2012, $4.2 billion in 2011, and $3.9 billion in 2010.  The Utility forecasts that capital expenditures will total approximately $5.1 billion in 2013, including expenditures related to its pipeline safety enhancement plan.  

Natural Gas Pipeline Safety Enhancement Plan

On December 28, 2012, the CPUC issued a decision that approved the Utility’s proposed pipeline safety enhancement plan (filed in August 2011) but disallowed the Utility’s request for rate recovery of a significant portion of plan-related costs the Utility forecasted it would incur over the first phase of the plan (2011 through 2014).  The CPUC decision limited the Utility’s recovery of capital expenditures to $1.0 billion of the total $1.4 billion requested.  As a result, the Utility recorded a charge of $353 million in 2012 for disallowed capital expenditures.  (See “Natural Gas Matters – CPUC Gas Safety Rulemaking Proceeding” below.)

Oakley Generation Facility

On December 20, 2012, the CPUC approved an amended purchase and sale agreement between the Utility and a third-party developer that provides for the construction of a 586-megawatt natural gas-fired facility in Oakley, California.  The CPUC authorized the Utility to recover the purchase price through rates.   During January 2013, several parties filed applications for rehearing of the CPUC decision.  PG&E Corporation and Utility are uncertain whether the CPUC will modify its decision based on these applications.

NATURAL GAS MATTERS

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows, have continued to be negatively affected by costs the Utility has incurred to improve the safety and reliability of the Utility’s natural gas operations, as well as by costs related to the on-going regulatory proceedings, investigations, and civil lawsuits related to the San Bruno accident and the Utility’s natural gas operations.  Since the San Bruno accident, PG&E Corporation and the Utility have incurred total cumulative charges to net income of $1.83 billion related to natural gas matters.

(in millions)	2012			2011			2010		Total
Pipeline-related expenses (1)	$	477		$	483		$	63	$	1,023
Disallowed capital expenditures (1)		353			-			-		353
Accrued penalties (2)		17			200			-		217
Third-party claims (3)		80			155			220		455
Insurance recoveries (3)		(185	)		(99	)		-		(284	)
Contribution to City of San Bruno (4)		70			-			-		70
Total natural gas matters	$	812		$	739		$	283	$	1,834

(1) See “CPUC Gas Safety Rulemaking Proceeding” below.

  (2) See “Pending CPUC Investigations and Enforcement Matters” below.

  (3) See “Third-Party Claims” below.

  (4) On March 12, 2012, the Utility and the City of San Bruno entered into an agreement under which the Utility contributed $70 million to support the city and the community’s recovery efforts.

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Pending CPUC Investigations and Enforcement Matters

The CPUC is conducting three investigations of the Utility’s natural gas operations that relate to (1) the Utility’s safety recordkeeping for its natural gas transmission system, (2) the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility’s pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the San Bruno accident.  (See Note 15 of the Notes to the Consolidated Financial Statements.)  Although the Utility, the CPUC’s Safety and Enforcement Division (“SED”), and other parties have engaged in settlement discussions in an effort to reach a stipulated outcome to resolve the investigations, the parties have not reached an agreement.  PG&E Corporation and the Utility are uncertain whether or when any stipulated outcome might be reached.  Any agreement regarding a stipulated outcome would be subject to CPUC approval.

The CPUC has concluded evidentiary hearings in each of these investigations.  The CPUC administrative law judges (“ALJs”) who oversee the investigations have adopted a revised procedural schedule, including the dates by which the parties’ briefs must be submitted.  The ALJs have also permitted the other parties (the City of San Bruno, The Utility Reform Network, and the City and County of San Francisco) to separately address in their opening briefs their allegations against the Utility, if any, in addition to the allegations made by the SED.  The ALJs have ordered the SED and other parties to file single coordinated briefs to address potential monetary penalties and remedies (which could include remedial operational or policy measures) for all three investigations by April 26, 2013.  After briefing has been completed, the ALJs will issue one or more presiding officer’s decisions listing the violations determined to have been committed, the amount of penalties, and any required remedial actions.  Based on the revised procedural schedule, one or more presiding officer’s decisions will be issued by July 23, 2013.  The decisions would become the final decisions of the CPUC thirty days after issuance unless the Utility or another party filed an appeal, or a CPUC commissioner requested review of the decision, within such time. (See “Penalties Conclusion” below.)

Other Potential Enforcement Matters

California gas corporations are required to provide notice to the CPUC of any self-identified or self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and the corporations’ natural gas operating practices.  The CPUC has authorized the SED to issue citations and impose penalties based on self-reported violations. In April 2012, the CPUC affirmed a $17 million penalty that had been imposed by the SED based on the Utility’s self-report that it failed to conduct periodic leak surveys because it had not included 16 gas distribution maps in its leak survey schedule.  (The Utility has paid the penalty and completed all of the missed leak surveys.)  As of December 31, 2012, the Utility has submitted 34 self-reports with the CPUC, plus additional follow-up reports.  The SED has not yet taken formal action with respect to the Utility’s other self-reports.  The SED may issue additional citations and impose penalties on the Utility associated with these or future reports that the Utility may file.  (See “Penalties Conclusion” below.)

In addition, in July 2012, the Utility reported to the CPUC that it had discovered that its access to some pipelines has been limited by vegetation overgrowth or building structures that encroach upon some of the Utility’s gas transmission pipeline rights-of-way.  The Utility is undertaking a system-wide effort to identify and remove encroachments from its pipeline rights-of-way over a multi-year period.  (See “Operating and Maintenance” above.)  PG&E Corporation and the Utility are uncertain how this matter will affect the above investigative proceedings related to natural gas operations, or whether additional proceedings or investigations will be commenced that could result in regulatory orders or the imposition of penalties on the Utility.

Penalties Conclusion

The CPUC can impose penalties of up to $20,000 per day, per violation. (For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation.)  The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged.  The CPUC has historically exercised this wide discretion in determining penalties. The CPUC's delegation of enforcement authority to the SED allows the SED to use these factors in exercising discretion to determine the number of violations, but the SED is required to impose the maximum statutory penalty for each separate violation that the SED finds.

The CPUC has stated that it is prepared to impose significant penalties on the Utility if the CPUC determines that the Utility violated applicable laws, rules, and orders.  In determining the amount of penalties the ALJs may consider the testimony of financial consultants engaged by the SED and the Utility.  The SED’s financial consultant prepared a report concluding that PG&E Corporation could raise approximately $2.25 billion through equity issuances, in addition to equity PG&E Corporation had already forecasted it would issue in 2012, to fund CPUC-imposed penalties on the Utility.  The Utility’s financial consultant disagreed with this financial analysis and asserted that a fine in excess of financial analysts’ expectations, which the consultant’s report cited as a mean of $477 million, would make financing more difficult and expensive.  The ALJs have scheduled a hearing to be held on March 4 and March 5, 2013 to consider the SED’s and Utility’s testimony.  The SED and other parties are scheduled to file briefs to address potential monetary penalties and remedies in all three investigations by April 26, 2013.

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PG&E Corporation and the Utility believe it is probable that the Utility will incur penalties of at least $200 million in connection with these pending investigations and potential enforcement matters and have accrued this amount in their consolidated financial statements.  PG&E Corporation and the Utility are unable to make a better estimate of probable losses or estimate the range of reasonably possible losses in excess of the amount accrued due to the many variables that could affect the final outcome of these matters and the ultimate amount of penalties imposed on the Utility could be materially higher than the amount accrued.  These variables include how the CPUC and the SED will exercise their discretion in calculating the amount of penalties, including how the total number of violations will be counted; how the duration of the violations will be determined; whether the amount of penalties in each investigation will be determined separately or in the aggregate; how the financial resources testimony submitted by the SED and the Utility will be considered; whether the Utility’s costs to perform any required remedial actions will be considered; and whether and how the financial impact of non-recoverable costs the Utility has already incurred, and will continue to incur, to improve the safety and reliability of its pipeline system, will be considered.  (See “CPUC Gas Safety Rulemaking Proceeding” below.)

These estimates, and the assumptions on which they are based, are subject to change based on many factors, including rulings, orders, or decisions that may be issued by the ALJs; whether the outcome of the investigations is resolved through a fully litigated process or a stipulated outcome that is approved by the CPUC; whether the SED will take additional action with respect to the Utility’s self-reports; and whether the CPUC or the SED takes any action with respect to the encroachment matter described above.  Future changes in these estimates or the assumptions on which they are based could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

CPUC Gas Safety Rulemaking Proceeding

The CPUC is conducting a rulemaking proceeding to develop and adopt new safety and reliability regulations for natural gas transmission and distribution pipelines in California and the related ratemaking mechanisms.  On December 28, 2012, the CPUC issued a decision that approved most of the Utility’s proposed pipeline safety enhancement plan to modernize and upgrade its natural gas transmission system, but disallowed the Utility’s request for rate recovery of a significant portion of plan-related costs the Utility forecasted it would incur over the first phase of the plan (2011 through 2014). 

In its application filed in August 2011, the Utility forecasted that it would incur total plan-related costs of approximately $2.2 billion, composed of $1.4 billion in capital expenditures and $750 million in expenses.  The CPUC decision prohibited the Utility from recovering any expenses incurred before December 20, 2012, the effective date of the decision, and from recovering certain categories of expenses that the Utility forecasts it will incur in 2013 and 2014.  The CPUC decision also limits the Utility’s recovery of capital expenditures to $1 billion.  The Utility will be unable to recover any costs in excess of the adopted capital and expense amounts and the adopted amounts will be reduced by the cost of any plan project not completed and not replaced with a higher priority project.  The CPUC also determined that the Utility should not recover in rates the costs of pressure testing pipeline placed into service after January 1, 1956 for which the Utility is unable to produce pressure test records.  The CPUC may disallow additional costs based on the final results of the Utility’s pipeline records search and pipeline pressure validation work, which the Utility expects to complete by May 2013.  The Utility is required to update its plan and file an application within 30 days after this work is completed.

The following table compares the Utility’s requested expense and capital amounts (based on forecasts included in the August 2011 application) with the amounts authorized by the CPUC:

(in millions)	2011			2012		2013		2014		Total
Expense
Requested	$	221	(1)	$	231	$	155	$	144	$	751
Authorized		-			3		73		89		165
Difference	$	221	(1)	$	228	$	82	$	55	$	586
Capital
Requested	$	69		$	384	$	480	$	500	$	1,433
Authorized		47			260		348		348		1,003
Difference	$	22		$	124	$	132	$	152	$	430

                                         (1) The Utility’s August 2011 application did not request recovery of forecast 2011 plan-related expenses of $221 million.

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For the year ended December 31, 2012, the Utility incurred total pipeline-related expenses of $477 million, including plan-related expenses of $271 million.  As a result of the decision, the Utility also recorded a charge of $353 million for capital expenditures that are forecast to exceed the CPUC’s authorized levels or that were specifically disallowed.  All plan-related costs for 2013 and 2014 will be charged to net income in the period incurred.  Unrecoverable plan-related costs are expected to range from approximately $150 million to $200 million in 2013 and a comparable amount in 2014.  The CPUC stated that the Utility’s recovery of the amounts authorized in the decision will be subject to refund, noting the possibility that further ratemaking adjustments may be made in the pending CPUC investigations in which the CPUC will address potential penalties to be imposed on the Utility.  (See “Pending CPUC Investigations and Enforcement Matters” above.)

The CPUC delegated authority to the SED to oversee all of the Utility’s work performed pursuant to the pipeline safety enhancement plan, including the authority to participate in all plan-related activities and review and modify all changes proposed by the Utility.  The Utility must submit quarterly compliance reports to the CPUC that will include information about actual cost compared to authorized cost for each work project; the construction status of projects; and changes in scope and prioritization of projects.  As a result of the compliance reporting process, the Utility could incur additional non-recoverable costs.  The CPUC also ordered the SED to engage consultants to conduct management and financial audits to address safety-related corporate culture and historical spending.  (As discussed below, the financial audit of the Utility’s natural gas distribution spending will be considered in the 2014 GRC, but the scope and timing of the management audit is still uncertain.) (See “2014 GRC” below.)     

On January 28, 2013, several parties filed applications for rehearing of the CPUC’s decision.  The applications for rehearing state, among other arguments, that the CPUC should have disallowed more of the Utility’s costs and that the CPUC should have approved a reduced ROE for capital expenditures made under the plan. Several parties also have filed petitions for modification of the decision.  It is uncertain whether or when the CPUC will grant these requests.

The second phase of the Utility’s pipeline safety enhancement plan in 2015 will focus on pipeline segments in less populated areas, as well as certain pressure testing and pipeline replacement work that the CPUC deferred from the first phase.  The Utility expects to address the scope, timing, and cost recovery of the second phase in late 2013 and request that changes to rates be made effective January 1, 2015. 

Criminal Investigation

The U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident and have indicated that the Utility is a target of the investigation.  The Utility is cooperating with the investigation.  PG&E Corporation and the Utility are uncertain whether any criminal charges will be brought against either company or any of their current or former employees.

PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Utility as a consequence of this investigation.

Third-Party Claims

In addition to the investigations and proceedings discussed above, at December 31, 2012, approximately 140 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, had been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 450 plaintiffs.  The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages.  These cases were coordinated and assigned to one judge in the San Mateo County Superior Court.  Many of the plaintiffs’ claims have been resolved through settlements.  The trial of the first group of remaining cases began on January 2, 2013 with pretrial motions and hearings.  On January 14, 2013, the court vacated the trial and all pending hearings due to the significant number of cases that have been settled outside of court.  The court has urged the parties to settle the remaining cases.  As of February 8, 2013, the Utility has entered into settlement agreements to resolve the claims of approximately 140 plaintiffs.  It is uncertain whether or when the Utility will be able to resolve the remaining claims through settlement.    

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At December 31, 2012, the Utility had recorded cumulative charges of $455 million for estimated third-party claims related to the San Bruno accident, including an $80 million charge made during 2012, primarily to reflect settlements and information exchanged by the parties during the settlement and discovery process.  The Utility estimates it is reasonably possible that it may incur as much as an additional $145 million for third-party claims, for a total possible loss of $600 million.  PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with punitive damages, if any, related to these matters.  The Utility has publicly stated that it is liable for the San Bruno accident and will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident.  (See Note 15 to the Consolidated Financial Statements.)

The Utility has recognized cumulative insurance recoveries of $284 million for third-party claims, which included $185 million for 2012 and $99 million for 2011.  Although the Utility believes that a significant portion of costs incurred for third-party claims relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries.  (See Note 15 to the Consolidated Financial Statements.)

Class Action Complaint

On August 23, 2012, a complaint was filed in the San Francisco Superior Court against PG&E Corporation and the Utility (and other unnamed defendants) by individuals who seek certification of a class consisting of all California residents who were customers of the Utility between 1997 and 2010, with certain exceptions.  The plaintiffs allege that the Utility collected more than $100 million in customer rates from 1997 through 2010 for the purpose of various safety measures and operations projects but instead used the funds for general corporate purposes such as executive compensation and bonuses.  To state their claims, the plaintiffs cited the SED’s January 2012 investigative report of the San Bruno accident that alleged, from 1996 to 2010, the Utility spent less on capital expenditures and operations and maintenance expense for its natural gas transmission operations than it recovered in rates, by $95 million and $39 million, respectively.  The SED recommended that the Utility should use such amounts to fund future gas transmission expenditures and operations.  Plaintiffs allege that PG&E Corporation and the Utility engaged in unfair business practices in violation of Section 17200 of the California Business and Professions Code (“Section 17200”) and claim that this violation also constitutes a violation of California Public Utilities Code Section 2106 (“Section 2106”), which provides a private right of action for violations of the California constitution or state laws by public utilities.  Plaintiffs seek restitution and disgorgement under Section 17200 and compensatory and punitive damages under Section 2106.

PG&E Corporation and the Utility contest the plaintiffs’ allegations.  In January 2013, PG&E Corporation and the Utility requested that the court dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs’ allegations.  In the alternative, PG&E Corporation and the Utility requested that the court stay the proceeding until the CPUC investigations described above are concluded.  The court has set a hearing on the motion for April 26, 2013.  Due to the early stage of this proceeding, PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses that may be incurred in connection with this matter.

Other Pending Lawsuits and Claim

In October 2010, a purported shareholder derivative lawsuit was filed in San Mateo Superior Court following the San Bruno accident 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, relating to the Utility’s natural gas business. The judge has ordered that proceedings in the derivative lawsuit be delayed until further order of the court.   On February 7, 2013, another purported shareholder derivative lawsuit was filed in U.S. District Court for the Northern District of California to seek recovery on behalf of PG&E Corporation for alleged breaches of fiduciary duty by officers and directors, among other claims. 

In February 2011, the Board of Directors of PG&E Corporation authorized PG&E Corporation to reject a demand made by another shareholder that the 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 of Directors members, officers, other employees, and third parties; and (3) adopt corporate governance initiatives and safety programs.  The Board of Directors also reserved the right to commence further investigation or litigation regarding the San Bruno accident if the Board of Directors deems such investigation or litigation appropriate.

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REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies.  The resolutions of these and other proceedings may affect PG&E Corporation’s and the Utility’s results of operations and financial condition.

2013 Cost of Capital Proceeding

On December 20, 2012, the CPUC issued a final decision authorizing the Utility to maintain a capital structure consisting of 52% equity, 47% long-term debt, and 1% preferred stock, beginning on January 1, 2013.  This capital structure applies to the Utility’s electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base.  In addition, the CPUC authorized the Utility to earn a rate of return on each component of the capital structure, including a ROE of 10.40%, compared to the 11% ROE requested by the Utility.  The following table compares the 2012 and 2013 authorized capital structure and rates of return:

	2012 Authorized									2013 Authorized
	Cost			Capital Structure			Weighted Cost			Cost			Capital Structure			Weighted Cost
Long-term debt		6.05	%		46	%		2.78	%		5.52	%		47	%		2.59	%
Preferred stock		5.68	%		2	%		0.11	%		5.60	%		1	%		0.06	%
Return on common equity		11.35	%		52	%		5.90	%		10.40	%		52	%		5.41	%
Overall Rate of Return								8.79	%								8.06	%

The Utility estimates that the 2013 revenue requirement associated with the authorized cost of capital will be approximately $235 million less than the currently authorized revenue requirement.  Approximately $165 million of this estimated decrease is attributable to the lower authorized ROE.  Changes to the Utility’s revenue requirement became effective on January 1, 2013.

The Utility and other parties have submitted a joint stipulation to the CPUC in which the parties agreed to continue the annual cost of capital adjustment mechanism that had been in effect since 2008, and to file the next full cost of capital applications in April 2015 for the 2016 test year.  Under the mechanism as proposed to be continued, the Utility’s ROE would be adjusted if the 12-month October-through-September average of the Moody's Investors Service long-term Baa utility bond index increases or decreases by more than 1.00% as compared to the applicable benchmark.   If the adjustment mechanism is triggered, the Utility’s authorized ROE, beginning January 1st of the following year, would be adjusted by one-half of the difference between the index and the benchmark.  Additionally, the Utility’s authorized costs of long-term debt and preferred stock would be updated to reflect actual August month-end embedded costs and forecasted interest rates for variable long-term debt, as well as new long-term debt and preferred stock scheduled to be issued.  In any year where the 12-month average yield triggers an automatic ROE adjustment, that average would become the new benchmark.

The CPUC is scheduled to issue a proposed decision by March 15, 2013 with a final decision by April 18, 2013.

2014 General Rate Case

On November 15, 2012, the Utility filed its 2014 GRC application with the CPUC.   In the Utility’s 2014 GRC, the CPUC will determine the annual amount of revenue requirements that the Utility will be authorized to collect from customers from 2014 through 2016 to recover its anticipated costs for electric and natural gas distribution and electric generation operations and to provide the Utility an opportunity to earn its authorized rate of return.  

The Utility has requested that the CPUC increase the Utility’s authorized base revenues for 2014 by a total of $1.28 billion over the comparable base revenues for 2013 that were previously authorized by the CPUC.  Over the 2014-2016 GRC period, the Utility plans to make annual additional capital investments of nearly $4 billion in electric and natural gas distribution and electric generation infrastructure.  The Utility forecasts that its 2014 weighted average rate base for the portion of the Utility’s business reviewed in the GRC will be $21.4 billion.

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The following tables compare the requested 2014 revenue requirement amounts by line of business with the comparable revenue requirements currently authorized for 2013:

(in millions)	Amounts requested in the		Amounts currently		Increase compared to currently
Line of Business:	GRC application		authorized for 2013		athorized amounts
Electric distribution	$	4,355	$	3,768	$	587
Gas distribution		1,810		1,324		486
Electric generation		1,946		1,737		209
Total revenue requirements	$	8,111	$	6,829	$	1,282

The Utility’s 2014 forecast for gas distribution operations includes increased costs to replace 180 miles of distribution line per year (compared to 30 miles currently), use new leak detection technologies and survey the entire system more frequently, remotely monitor and control a significant number of valves, implement an asset management system to provide detailed, readily accessible information about the gas distribution system, and reduce response times for customer gas odor reports.  The Utility’s forecast for electric distribution operations includes increased costs to upgrade and replace assets to improve safety and reduce outages, use infrared technology to identify and correct equipment issues, install more automation to limit the impact and duration of outages, mitigate wildfire risk, increase system capacity to meet new customer demand, and enhance asset records management and integrate it with key systems.  The Utility’s forecast for electric generation includes increased costs to operate the Utility’s hydroelectric system (including costs related to the Helms pumped storage facility and costs associated with operating licenses issued by the FERC), comply with new requirements adopted by the NRC applicable to the Utility’s Diablo Canyon nuclear power plant, and operate and maintain the Utility’s fossil fuel-fired and other generating facilities.  In addition, the Utility’s forecast includes increased costs to improve service at the Utility’s local offices and customer contact centers and to improve the service provided by field account representatives to small and mid-sized business customers.

In its application, the Utility has requested that the CPUC establish new balancing accounts to allow the Utility to recover costs associated with gas leak survey and repair work, major emergencies, and new regulatory requirements related to nuclear operations and hydroelectric relicensing, because these costs are subject to a high degree of uncertainty.  The Utility also requested that the CPUC establish a ratemaking mechanism that would increase the Utility’s authorized revenues in 2015 and 2016, primarily to reflect increases in rate base due to capital investments in infrastructure and, to a lesser extent, anticipated increases in wages and other expenses.  The Utility also has requested that revenue requirements be adjusted to reflect certain externally driven changes in the Utility’s costs, such as changes in franchise fees.  The Utility estimates that this mechanism would result in increases in revenue of $492 million in 2015 and an additional $504 million in 2016.

Independent consultants engaged by the SED are reviewing and evaluating certain operational plans underlying the Utility’s 2014 cost forecast to ensure that safety and security concerns have been addressed and that the plans properly incorporate risk assessments and mitigation measures.  The SED has also engaged independent consultants to conduct a financial audit of the Utility’s gas distribution system, which will examine the Utility’s authorized and budgeted capital investments and operation and maintenance expenditures for its last two authorized GRC cycles.  The SED reports on the results of the consultants’ evaluations and financial audit are due May 31, 2013.  The Utility and other parties will be able to respond to the reports.

According to the CPUC’s current procedural schedule for the proceeding, which may be subject to change in the future, the CPUC’s Division of Ratepayer Advocates (“DRA”) is scheduled to serve its report on the Utility’s application by May 3, 2013.  Additional testimony from other parties must be submitted by May 17, 2013.  The schedule contemplates evidentiary hearings to be held this summer, followed by a proposed decision to be released in November 2013 and a final CPUC decision to be issued in December 2013.  If the decision is delayed, the Utility will, consistent with CPUC practice in prior GRCs, request that the CPUC issue an order directing that the authorized revenue requirement changes be effective January 1, 2014, even if the decision is issued after that date.

FERC Transmission Owner Rate Case

On September 28, 2012, the Utility filed an application with the FERC to increase the Utility’s retail and wholesale electric transmission customer rates that have been in effect since March 1, 2011.  The proposed rate changes will become effective on May 1, 2013, subject to refund following the FERC’s issuance of a final decision.  The most significant factors driving the requested increase are the Utility’s continuing needs to replace and modernize aging electric transmission infrastructure; to interconnect new electric generation, including renewable resources; and to accommodate the magnitude and location of forecasted electric load growth in California.  The Utility forecasts that it will make investments of $783 million in 2012 and an additional $837 million in 2013 in various capital projects, including projects to add transmission capacity, expand automation technology, improve overall system reliability, and maintain and replace equipment at substations.  The proposed rate base in 2013 is forecast to be $4.5 billion compared to $3.6 billion in 2011.  The operations and maintenance costs associated with this request are forecast to be approximately $191 million in 2013, compared to $152 million in 2011.

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Compared to present rates, the Utility estimated that revenues would increase by $254 million based on the Utility’s requested ROE of 11.5%, for total 2013 electric transmission revenues of $1.2 billion.  On November 29, 2012, the FERC issued an order that accepted the Utility’s application but directed the Utility to reduce its proposed revenue requirement and rates to reflect the median ROE of a comparative group of other utilities.  In response to the FERC’s order, on December 21, 2012, the Utility revised its requested revenue requirements and rates to reflect a 9.1% ROE.   Based on the reduced ROE, the Utility estimates that revenues would increase by approximately $158 million, for total annual electric transmission revenues of $1.1 billion beginning on May 1, 2013.  On December 21, 2012, the Utility also filed a request for rehearing of the FERC’s order.  It is uncertain when the FERC will act on the request for rehearing.  The ultimate resolution of revenue requirements and rates will be addressed through hearings and settlement procedures.

Energy Efficiency Programs and Incentive Ratemaking

On December 20, 2012, the CPUC approved a new energy efficiency incentive mechanism to reward the Utility and other California energy utilities for the successful implementation of their 2010-2012 energy efficiency programs.  The CPUC awarded the Utility $21 million for the successful implementation of the Utility’s 2010 energy efficiency programs.  The CPUC decision also established the process that is expected to apply to incentive claims for program years 2011 and 2012.  After the CPUC completes its audit of the utilities’ 2011 program expenditures, the utilities must file their incentive claims in the third quarter of 2013 for approval by the CPUC in the fourth quarter of 2013. Similarly, the utilities will file their incentive claims based on the CPUC-audited 2012 program expenditures in the third quarter of 2014 for approval by the CPUC in the fourth quarter of 2014.

Diablo Canyon Nuclear Power Plant

In March 2012, the NRC issued several orders to the owners of all U.S. operating nuclear reactors to implement the highest-priority recommendations issued by the NRC’s task force to incorporate the lessons learned from the March 2011 earthquake and tsunami that caused significant damage to the Fukushima-Dai-ichi nuclear facilities in Japan.  Among other directives, the NRC requested nuclear power plant owners to provide additional information about seismic and flooding hazards and emergency preparedness. In response to the orders, the utilities are required to re-evaluate the models used to determine compliance with the license conditions relating to seismic and flooding design.  Each nuclear power plant owner will be required to be in full compliance with the NRC orders within two refueling outages or by December 31, 2016, whichever comes first. The Utility has already provided the initially requested information to the NRC and will continue to respond to the NRC orders as required.  After reviewing the information submitted by the Utility and other nuclear power plant owners, the NRC may issue further orders which may include facility-specific orders.  The Utility will incur costs to comply with Fukushima related NRC orders.  The Utility has requested that the CPUC allow the Utility to recover costs incurred in 2014 through 2016 to comply with NRC orders through rates to be authorized by the CPUC in the Utility’s 2014 GRC.

The Utility also has filed an application at the NRC to renew the operating licenses for the two operating units at Diablo Canyon which expire in 2024 and 2025.  In May 2011, after the Fukushima-Dai-ichi event, the NRC granted the Utility’s request to delay processing the Utility’s application until certain advanced seismic studies were completed by the Utility.  When the Utility began the studies in 2010, it was anticipated that the studies would be completed in 2013 or 2014, depending upon whether required permits were timely obtained from environmental and local government agencies.  In November 2012, the California Coastal Commission denied the Utility’s request for permits to conduct off-shore three-dimensional high-energy seismic studies, in part, based on the finding that, because the studies were not necessary for NRC compliance, the potential environmental effects did not outweigh the risks.  The Utility has completed the data collection phases for the on-shore advanced seismic studies as well as other off-shore low-energy seismic studies.  The Utility is assessing whether it has sufficient seismic data without conducting high energy off-shore studies or if other studies are needed.  Depending on the outcome of the Utility’s assessment, it is uncertain when the Utility would request the NRC to resume the relicensing proceeding.  In order to receive renewed operating licenses, the Utility also must undergo a consistency review by the California Coastal Commission. The disposition of the Utility’s relicensing application also will be affected by the terms and timing of the NRC’s “waste confidence” decision regarding the environmental impacts of the storage of spent nuclear fuel which is not expected to be issued before September 2014.  The NRC has stated that it will not take action in licensing or re-licensing proceedings until it issues a new “waste confidence decision.”  (See “Risk Factors” below.)

Finally, the CPUC is also considering the Utility’s application to recover estimated costs to decommission the Utility’s nuclear facilities at Diablo Canyon and the retired nuclear facility located at the Utility’s Humboldt Bay Generation Station.  The Utility files an application with the CPUC every three years requesting approval of the Utility’s estimated decommissioning costs and authorization to recover the estimated costs through rates.  (See the discussion of the 2012 Nuclear Decommissioning Cost Triennal Proceeding in Note 2 of the Notes to the Consolidated Financial Statements.)

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Other Matters

Electric Distribution Facilities

The Utility conducted a system-wide review of its patrol and inspection records for underground and overhead electric distribution facilities after the Utility reported to the CPUC in July 2012 that some of the Utility’s facilities were not patrolled and/or inspected at the periodic intervals required by the CPUC’s rules. The Utility concluded a system-wide review and found that approximately 0.4% of its total electric distribution facilities had not been patrolled and/or inspected at the intervals required by CPUC rules.  The Utility has submitted the results of its review to the SED and has completed the patrols and inspections of all such facilities.

In October 2012, the Utility also reported to the CPUC that it planned to re-inspect electric distribution underground and overhead facilities that had been identified as inspected by a contractor after a review determined that the inspection practices used by some of the contractor’s employees did not meet the Utility’s standards.  The re-inspections have been completed.

PG&E Corporation and the Utility are uncertain how the above matters will affect the other regulatory proceedings and current investigations involving the Utility, or whether additional proceedings or investigations will be commenced that could result in regulatory orders or the imposition of penalties on the Utility.

Residential Rate Design

In June 2012, the CPUC opened a rulemaking proceeding to examine electric rate design for residential customers among California’s electric utilities and consider regulatory and legislative changes that may be needed to the current rate structure.  PG&E Corporation and the Utility are uncertain how the outcome of this rulemaking proceeding will affect the Utility’s future electric rate structure.

ENVIRONMENTAL MATTERS

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

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.)

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor sites.  The Utility is also required to take measures to abate the effects of the contamination on the environment.  At the Hinkley natural gas compressor site, the Utility’s remediation and abatement efforts are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region (“Regional Board”).  The Regional Board has issued several orders directing the Utility to implement interim remedial measures to reduce the mass of the underground plume of hexavalent chromium, monitor and control movement of the plume, and provide replacement water to affected residents.

The Utility submitted its proposed final remediation plan to the Regional Board in September 2011 recommending a combination of remedial methods to clean up groundwater contamination, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water.  In August 2012, the Regional Board issued a draft environmental impact report (“EIR”) that evaluated the Utility’s proposed methods and the potential environmental impacts.  The Utility expects that the Regional Board will consider certification of the final EIR in the second quarter of 2013.  Following certification of the EIR, the Regional Board is expected to issue the final cleanup standards.

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The Regional Board ordered the Utility in October 2011 to provide an interim and permanent replacement water system for resident households located near the chromium plume that have domestic wells containing hexavalent chromium in concentrations greater than 0.02 parts per billion.  The Utility filed a petition with the California State Water Resources Control Board (“California Water Board”) to contest certain provisions of the order.  In June 2012, the Regional Board issued an amended order to allow the Utility to implement a whole house water replacement program for resident households located near the chromium plume boundary.  Eligible residents may decide whether to accept a replacement water supply or have the Utility purchase their properties, or alternatively not participate in the program.  As of January 31, 2013, approximately 350 residential households are covered by the program and the majority have opted to accept the Utility’s offer to purchase their properties.  The Utility is required to complete implementation of the whole house water replacement systems by August 31, 2013.  The Utility will maintain and operate the whole house replacement systems for five years or until the State of California has adopted a drinking water standard specifically for hexavalent chromium at which time the program will be evaluated.

At December 31, 2012 and 2011, $226 million and $149 million, respectively, were accrued in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley site.  The increase primarily reflects the Utility’s best estimate of costs associated with the developments described above.  Remediation costs for the Hinkley natural gas compressor site are not recovered from customers through rates.  Future costs will depend on many factors, including the Regional Board’s certification of the final EIR, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the Utility’s required time frame for remediation, and adoption of a final drinking water standard currently under development by the State of California, as mentioned above.  As more information becomes known regarding these factors, these estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to further changes.  Future changes in estimates or assumptions may have a material impact on PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows. 

Climate Change

A report issued in 2012 by the U.S. Environmental Protection Agency (“EPA”) entitled, “Climate Change Indicators in the United States, 2012” states that the increase of GHG emissions in the atmosphere is changing the fundamental measures of climate in the United States, including rising temperatures, shifting snow and rainfall patterns, and more extreme climate events. (See “Risk Factors” below.)  Although no comprehensive federal legislation has been enacted to address the reduction of GHG emissions, the California legislature has taken action to address climate change.

GHG Cap-and-Trade

The California Global Warming Solutions Act of 2006 (also known as California Assembly Bill 32 or AB 32) requires the gradual reduction of state-wide GHG emissions to the 1990 level by 2020.  The California Air Resources Board (“CARB”) is the state agency charged with monitoring GHG levels and adopting regulations to implement and enforce AB 32.  The CARB has approved various regulations, including regulations that established a state-wide, comprehensive “cap-and-trade” program that sets a gradually declining limit (or “cap”) on the amount of GHGs that may be emitted by the major sources of GHG emissions each year.  The cap and trade program’s first two-year compliance period, which began January 1, 2013, applies to the electricity generation and large industrial sectors.  The next compliance period, from January 1, 2015 through December 31, 2017, will expand to include the natural gas supply and transportation sectors, effectively covering all the capped sectors until 2020.  Emitters may meet up to 8% of their compliance obligation through the purchase of “offset credits” which represent GHG emissions abatement achieved in sectors that are not subject to the cap.

Each year the CARB will issue emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year.  Emitters (also known as covered entities) are required to obtain and surrender allowances equal to the amount of their GHG emissions within a particular compliance period.  Emitters can obtain allowances from the CARB at quarterly auctions held by the CARB or from third parties or exchanges on the secondary market for trading GHG allowances.  The CARB’s first quarterly auction was held on November 14, 2012.

Also, during each year of the program, the CARB will allocate a fixed number of allowances (which will decrease each year) for free to regulated electric distribution utilities, including the Utility, for the benefit of their electricity customers.  The utilities are required to consign their allowances for auction by the CARB.  The CPUC has ordered the utilities to allocate their auction revenues, including accrued interest, among certain classes of their electricity distribution customers in accordance with existing state law.  Although the CPUC had previously authorized the utilities to recover their GHG compliance costs through rates, the CPUC decided that the recovery of GHG compliance costs should be deferred until the CPUC adopted a final auction revenue allocation methodology.  Until a final methodology is adopted, the utilities have been ordered to track GHG costs and auction revenues for future rate recovery.  (See Note 3 of the Notes to the Consolidated Financial Statements.)  The CARB has not yet decided whether and to what extent allowances will be freely allocated to regulated gas utilities for the benefit of their natural gas customers starting in the second compliance period beginning in 2015.

The Utility expects all costs and revenues associated with GHG cap-and-trade to be passed through to customers.

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Renewable Energy Resources

California’s Renewables Portfolio Standard (“RPS”) program increases the amount of renewable energy that load-serving entities, such as the Utility, must deliver to their customers from at least 20% of their total retail sales, as required by the prior law, to 33% of their total retail sales.  The RPS program, which became effective in December 2011, established compliance periods: 2011 through 2013, 2014 through 2016, 2017 through 2020, and 2021 and thereafter.  The RPS compliance requirement that must be met for each of these compliance periods will gradually increase through 2020 and will be determined on an annual basis thereafter.  In June 2012, the CPUC adopted rules for transitioning between the prior 20% RPS program and the 33% RPS program, applying excess procurement quantities across compliance periods, using procurement from short-term contracts to meet compliance requirements, and reporting annual RPS compliance to the CPUC. 

The Utility has made substantial financial commitments under third-party renewable energy contracts to meet RPS procurement quantity requirements.  (See Note 15 of the Notes to the Consolidated Financial Statements.)  The Utility currently forecasts that it will comply with its procurement requirements.  The costs incurred by the Utility under third-party contracts to meet RPS requirements are expected to be recovered with other procurement costs through rates.  The costs of Utility-owned renewable generation projects will be recoverable through traditional cost-of-service ratemaking mechanisms provided that costs do not exceed the maximum amounts authorized by the CPUC for the respective project.

Water Quality

The EPA published draft regulations in April 2011 to implement the requirements of the federal Clean Water Act that requires 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.  In June 2012, the EPA proposed changes to these draft regulations which, if adopted, would provide more flexibility in complying with some of the requirements.  The EPA is required to issue final regulations by July 2013.

At the state level, the California Water Board has adopted a policy on once-through cooling that generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities in California by at least 85%.  The California Water Board has appointed a committee to evaluate the feasibility and cost of using alternative technologies to achieve compliance at nuclear power plants.  The committee’s assessment is due by October 2013.  If the California 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.  If the California Water Board requires the installation of cooling towers that the Utility believes are not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge.  The Utility’s Diablo Canyon operations must be in compliance with the California Water Board’s policy by December 31, 2024.

LEGAL MATTERS

In addition to the provisions made for contingencies related to the San Bruno accident, PG&E Corporation’s and the Utility’s Consolidated Financial Statements also include provisions for claims and lawsuits that have arisen in the ordinary course of business, regulatory proceedings, and other legal matters.  (See “Legal and Regulatory Contingencies” in Note 15 of the Notes to the Consolidated Financial Statements.)

OFF-BALANCE SHEET ARRANGEMENTS

PG&E Corporation and the Utility do not have any 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).

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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, electric transmission, natural gas transportation, and storage; emissions allowances, 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 risk 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 federal financial reform legislation, the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”).  PG&E Corporation and the Utility are implementing programs to comply with the final regulations that have been issued pursuant to Dodd-Frank.

Commodity 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.  Such fluctuations, however, 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 its 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.

The Utility’s value-at-risk calculated under the methodology described above was approximately $13 million and $11 million at December 31, 2012 and 2011, respectively.  During the 12 months ended December 31, 2012, the Utility’s approximate high, low, and average values-at-risk were $13 million, $10 million and $12 million, respectively. And during 2011, the value-at-risk amounts were $11 million, $7 million and $9 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, 2012 and December 31, 2011, if interest rates changed by 1% for all current PG&E Corporation and Utility variable rate and short-term debt and investments, the change would affect net income for the next 12 months by $7 million and $13 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

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Energy Procurement 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 fails 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, 2012 and December 31, 2011:

													Net Credit
											Number of		Exposure to
	Gross Credit										Wholesale		Wholesale
	Exposure										Customers or		Customers or
	Before Credit			Credit				Net Credit			Counterparties		Counterparties
(in millions)	Collateral (1)			Collateral				Exposure (2)			>10%		>10%
December 31, 2012		$	94		$	(9	)		$	85		2		62
December 31, 2011			151			(13	)			138		2		106

(1) Gross credit exposure equals mark-to-market value on physically and financially settled contracts, 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 accounting principles generally accepted in the United States of America (“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.

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 regulatory assets, 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 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 during 2012, 2011, and 2010, the recovery of any material costs previously recognized by the Utility as regulatory assets.

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If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made.  At December 31, 2012, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $8.3 billion and regulatory liabilities (including current balancing accounts payable) of $6.1 billion.

Loss Contingencies

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, gas compressor stations, 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 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 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 or a range of possible losses.  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, as well as site conditions, thereby possibly affecting the cost of the remediation effort.

At December 31, 2012 and 2011, the Utility’s accruals for undiscounted gross environmental liabilities were $910 million and $785 million, respectively.  The Utility’s undiscounted future costs could increase to as much as $1.6 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 and Regulatory 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 subject to claims or named as parties in lawsuits.  In addition, the Utility can incur penalties for failure to comply with federal, state, or local laws and regulations.  PG&E Corporation and the Utility record a provision for a loss when it is both probable that a loss 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 losses and record a provision based on the minimum amount, 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 (or reasonably possible losses in excess of the amounts accrued), 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 the amount of such losses, PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs.  (See “Legal and Regulatory Contingencies” in Note 15 of the Notes to the Consolidated Financial Statements.)

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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 expenses 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-fired generation facilities.  The Utility estimates its obligation for the future decommissioning of its nuclear generation facilities and certain fossil fuel-fired generation facilities.  In December 2012, the Utility submitted an updated estimate of the cost to decommission its nuclear facilities to the CPUC.  The increase in the estimated obligation of $1.3 billion was primarily due to higher spent nuclear fuel disposal costs and an increase in the scope of work.  To estimate the liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, 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 1.57%.  Similarly, an increase in the discount rate by 25 basis points would decrease the amount of the ARO by 4.03%.  At December 31, 2012, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was $2.9 billion.

Pension and Other Postretirement Benefit Plans

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees as well as contributory postretirement health care and medical plans for eligible retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.

The pension and other postretirement benefit obligations are calculated using actuarial models as of the December 31 measurement date.  The significant actuarial assumptions used in determining pension and other benefit obligations include the discount rate, the average rate of future compensation increases, the health care cost trend rate and the expected return on plan assets.  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.

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); or, to the extent that the cost of the plans are recoverable in utility rates, to regulatory assets and liabilities, resulting in no impact to their respective Consolidated Statements of Income.

Pension and other benefit expense is based on the differences between actuarial assumptions and actual plan results and is deferred in accumulated other comprehensive income (loss) and amortized into income on a gradual basis.  The differences between pension benefit expense recognized in accordance with GAAP and amounts recognized for ratemaking purposes are recorded as regulatory assets or liabilities as amounts are probable of recovery from customers.  (See Note 3 of the Notes to the Consolidated Financial Statements.)  

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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 2012 is 7.5%, gradually decreasing to the ultimate trend rate of 5% in 2018 and beyond.

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 5.4% compares to a ten-year actual return of 10.2%.

The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 648 Aa-grade non-callable bonds at December 31, 2012.  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 2012 Pension Costs			Increase in Projected Benefit Obligation at December 31, 2012
Discount rate		(0.50	) %		$	110		$	1,262
Rate of return on plan assets		(0.50	) %			54			-
Rate of increase in compensation		0.50	%			50			308

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 2012 Other Postretirement Benefit Costs			Increase in Accumulated Benefit Obligation at December 31, 2012
Health care cost trend rate		0.50	%		$	4		$	53
Discount rate		(0.50	) %			2			132
Rate of return on plan assets		(0.50	) %			7			-

RISK FACTORS

PG&E Corporation’s and the Utility’s reputations have been significantly affected by the negative publicity surrounding the San Bruno accident, the related investigations and civil litigation, and the various reports the Utility has submitted to the CPUC to disclose noncompliance with applicable regulations.  Their reputations may be further adversely affected by publicity regarding developments in the pending CPUC and criminal investigations, and by future investigations or other regulatory or governmental proceedings that may be commenced, and by media or public scrutiny of the Utility’s electricity and natural gas operations. Such further reputational harm or the inability of PG&E Corporation and the Utility to restore their reputations may further affect their financial conditions, results of operations and cash flows.

The reputations of PG&E Corporation and the Utility have seriously suffered as a result of the San Bruno accident for which the Utility has acknowledged liability; the June 2011 investigative report from the CPUC’s independent review panel and the August 2011 National Transportation Safety Board (“NTSB”) report, both of which criticized the Utility’s safety recordkeeping for its natural gas transmission system and the Utility’s pipeline installation, integrity management, and other operational practices; and the media coverage of the accident and the related investigations and lawsuits. After the San Bruno accident, the CPUC initiated three investigations pertaining to the Utility’s natural gas transmission pipeline operations, including an investigation of the San Bruno accident.  (See “Natural Gas Matters” above.)  A criminal investigation of the San Bruno accident also has been commenced. The media also has widely reported on the civil lawsuits arising from the San Bruno accident which seek compensation and punitive damages for personal injuries, deaths, and property damage.

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In addition, the Utility has notified the SED of various self-identified violations of regulations applicable to natural gas safety and operating practices since December 2011 when the CPUC imposed the self-reporting requirement and authorized the SED to impose penalties based on the self-identified violations.  In January 2012, the SED imposed penalties of $17 million on the Utility for self-reported failure to perform certain leak surveys and the SED may impose additional penalties based on other self-reported violations.  These self-reports also have received negative media attention.

The Utility’s operations are also subject to heightened and well-publicized concerns about many aspects of its operations, such as the Utility’s nuclear generation operations at Diablo Canyon and the risks of terrorist acts, earthquakes, or a nuclear accident; the Utility’s environmental remediation activities; and the accuracy, privacy, and safety of the Utility’s information and operating systems, including those used to measure customer energy usage and generate bills. These concerns have often led to additional adverse media coverage and could later result in investigations or other action by regulators, legislators and law enforcement officials or in lawsuits. 

Further, these concerns may cause investors to question management’s ability to repair the reputational harm that PG&E Corporation and the Utility have suffered, resulting in an adverse impact on the market price of PG&E Corporation common stock.  Given PG&E Corporation’s and the Utility’s greater equity needs, a declining stock price would cause further dilution in net income per share.  The extent to which their reputations can be restored will depend, in part, on the success of the Utility’s efforts to improve the safety and reliability of the natural gas system as planned in the Utility’s pipeline safety enhancement plan, whether they can respond to the findings and recommendations made by the CPUC’s independent review panel and the NTSB, and whether they are able to adequately convince regulators, legislators, law enforcement officials, the media and the public that they have done so.  Their ability to repair their reputations also may be affected by developments that may occur in the pending investigations, including the amount of civil or criminal penalties that may be imposed on the Utility; whether there are new investigations or citations; and developments that may occur in the San Bruno accident-related civil litigation.  If PG&E Corporation and the Utility are unable to repair their reputations, their financial conditions, results of operations and cash flows may be further negatively affected.

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially affected by the ultimate amount of penalties imposed on the Utility; the costs of taking required remedial actions; the ultimate amount of criminal penalties, if any, imposed by governmental authorities; and the ultimate amount of third–party liability arising from the San Bruno accident and the availability, timing and amount of related insurance recoveries.

The CPUC has stated that it is prepared to impose substantial penalties on the Utility in connection with the investigations.  Although the parties have engaged in settlement discussions in an effort to reach a stipulated outcome to resolve the investigations, the parties have not  reached an agreement.  If a stipulated outcome is not reached and the CPUC issues a decision that finds that the Utility violated applicable laws, rules or orders, the CPUC can impose penalties of up to $20,000 per day, per violation. (For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation.)  The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged.  The CPUC has historically exercised this discretion in determining penalties.  The SED also has this discretion under the authority delegated to it by the CPUC, but the SED is required to impose the maximum statutory penalty per violation, per day.

PG&E Corporation and the Utility have concluded that it is probable that the Utility will be required to pay penalties in connection with the investigations and potential SED enforcement related to the self-reports and have accrued an amount in their financial statements that reflects the reasonably estimable minimum amount of penalties they believe it is probable that the Utility will incur.  After considering the many variables that could affect the ultimate amount of penalties the Utility may be required to pay, PG&E Corporation and the Utility are unable to make a better estimate of the probable loss or estimate the reasonably possible amount of penalties that the Utility could incur in excess of the amount accrued and such amount could be material.  In addition to penalties, the Utility could incur significant costs to implement any remedial actions the CPUC may order the Utility to perform.

PG&E Corporation and the Utility also are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any criminal penalties that may be imposed in connection with the pending criminal investigation.  Any civil or criminal penalties imposed on the Utility will not be recoverable from customers.  (See Note 15 of the Notes to the Consolidated Financial Statements.)  PG&E Corporation and the Utility also have concluded that it is probable that the Utility will incur a loss in connection with the lawsuits arising from the San Bruno accident and have accrued an amount in their financial statements for the reasonably estimable minimum amount of loss.  PG&E Corporation and the Utility believe that a significant portion of the third-party liabilities the Utility incurs will be recoverable through insurance, but there is a risk that the insurers could deny coverage for claims under the terms of the policies, deem settlement amounts excessive and not payable, or be financially unable to pay the Utility’s claims.  Further, although many of the San Bruno lawsuits have been settled, a substantial number of cases are unresolved and plaintiffs continue to pursue compensatory and punitive damages.  PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any punitive damages that could be awarded to plaintiffs in the civil litigation.  (See Note 15 of the Notes to the Consolidated Financial Statements.)

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The estimates and assumptions underlying the accrued amounts and the ultimate amount of penalties and third-party losses are subject to change based on the amount of penalties actually imposed by the CPUC or agreed to in a stipulated outcome that may be reached to resolve the investigations, by the outcome of trials in the San Bruno litigation, and the terms of additional settlement agreements that may be reached with remaining plaintiffs.  Future changes to estimates and assumptions could result in additional accruals in future periods which could have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations in the period in which they are recognized.

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows have been, and will continue to be, materially affected by costs incurred by the Utility to perform work under its pipeline safety enhancement plan, to undertake other pipeline-related work, and to improve the safety and reliability of its natural gas and electricity operations.

Although the CPUC approved most of the proposed scope and timing of projects under the Utility’s pipeline safety enhancement plan, the CPUC disallowed the Utility’s request for rate recovery of a significant portion of capital costs and expenses through 2014, including costs of pressure testing pipelines placed into service after January 1, 1956 for which the Utility is unable to produce pressure test records.  The CPUC may disallow additional costs based on the final results of the Utility’s pipeline records search and pipeline pressure validation work, which the Utility expects to complete by May 2013.  (See “Natural Gas Matters” above.)  The Utility will be unable to recover any costs in excess of the adopted capital and expense amounts and the adopted amounts will be reduced by the cost of any plan project not completed during the first phase and not replaced with a higher priority project.  Further, actual costs for 2013 and 2014 may be materially higher than the Utility currently forecasts. During 2013, the Utility expects to request that the CPUC approve the proposed timing, scope and cost recovery for the first three years (2015, 2016, and 2017) of the second phase of the plan beginning on January 1, 2015.  While the Utility’s request will include updated cost forecasts based on the Utility’s experience during the first phase, there is some risk that categories of costs that were disallowed by the CPUC in its decision on the first phase also will be disallowed in the second phase.

In addition, the Utility forecasts that it will incur additional costs outside of the scope of the pipeline safety enhancement plan in 2013 and 2014 that are not expected to be recoverable through rates.  This includes costs to establish the parameters of the Utility’s “rights-of-way” surrounding pipelines and to identify and remove encroachments from these pipeline rights-of-way.  The Utility also forecasts it will continue to incur additional costs associated with the integrity of transmission pipelines, conduct other gas-related work, and legal and regulatory expenses.  The Utility also forecasts that it will incur costs to improve electric and gas distribution operations in 2013 that exceed the amounts assumed when rates were set in the last rate cases.  (See “Operating and Maintenance” above.)  Actual costs may be materially higher than forecast.  Further, as the Utility continues to review its natural gas system and operating practices and as industry practices and standards evolve, the Utility may undertake additional work in the future to improve the safety and reliability of its natural gas utility services, for example, to validate the maximum allowable operating pressure of other facilities in its natural gas transmission system, such as compressor stations.  The Utility may be unable to recover the costs of such additional work through rates.  The Utility also may incur third-party liability related to service disruptions caused by changes in pressure on its natural gas transmission system as work is performed.

PG&E Corporation’s and the Utility’s financial condition depends upon the Utility’s ability to recover its operating expenses and its electricity and natural gas procurement costs and to earn a reasonable rate of return on capital investments, in a timely manner from the Utility’s customers through regulated rates.

The Utility’s ability to recover its costs and earn its authorized rate of return can be affected by many factors, including the time lag between when costs are incurred and when those costs are recovered in customers’ rates and differences between the forecast or authorized costs embedded in rates (which are set on a prospective basis) and the amount of actual costs incurred.  (See “Regulatory Matters – 2014 General Rate Case” above.)  The CPUC or the FERC may not allow the Utility to recover costs on the basis that such costs were not reasonably or prudently incurred or for other reasons.  For example, the CPUC has prohibited the Utility from recovering a material portion of costs that the Utility has already incurred, and will continue to incur, as it performs work under the pipeline safety enhancement plan, in part, because the CPUC found that such costs were incurred as a result of imprudent management. The CPUC may order the Utility to propose cost-sharing methods for certain costs or the Utility may decide for other reasons not to seek recovery of certain costs.  In either case, the Utility would incur costs that are not recovered through rates.  (See “Natural Gas Matters” above.)

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Further, to serve its customers in a safe and reliable manner, the Utility may be required to incur expenses before the CPUC approves the recovery of such costs.  The Utility is generally unable to recover costs incurred before CPUC authorization is obtained, unless the CPUC authorizes the Utility to track costs for potential future recovery.  For example, the Utility requested that the CPUC allow the Utility to track costs incurred in 2012 under the pipeline safety enhancement plan before the CPUC approved the plan.  The CPUC did not address the Utility’s request and as a result the Utility was unable to recover costs incurred before the effective date of the decision, December 20, 2012.  The Utility’s failure to recover these and other pipeline-related costs has materially affected PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows.

Fluctuating commodity prices, changes in laws and regulations or changes in the political and regulatory environment also may have an adverse effect on the Utility’s ability to timely recover its costs and earn its authorized rate of return.  Current law and regulatory mechanisms permit the Utility to pass through its costs to procure electricity and natural gas to customers in rates.  A significant and sustained rise in commodity prices, caused by costs associated with new renewable energy resources and California’s new cap-and-trade program and other factors, could create overall rate pressures that make it more difficult for the Utility to recover its costs.  This pressure could increase as the Utility continues to collect authorized rates to support public purpose programs, such as energy efficiency programs, and low-income rate subsidies, and to fund customer incentive programs.   Further, current California law restricts the ability of the CPUC to adjust electricity rates for certain customer classes which could lead to a perception that some customers are unfairly subsidizing other customers and that some commercial customers are competitively disadvantaged as compared to similar customers in other states.  The customer concerns caused by these perceived inequities could also make it more difficult for the Utility to recover its operational costs.

The Utility’s ability to recover its costs also may be affected by the economy and the economy’s corresponding impact on the Utility’s customers.  For example, a sustained downturn or sluggishness in the economy 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.  A portion of the Utility’s revenues depends on the level of customer demand for the Utility’s natural gas transportation services which can fluctuate based on economic conditions, the price of natural gas, and other factors.

The Utility’s failure to recover its operating expenses, including electricity and natural gas procurement costs in a timely manner through rates could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

The Utility’s ability to procure electricity to meet customer demand at reasonable prices and recover procurement costs timely may be affected by increasing renewable energy requirements, the continuing functioning of the wholesale electricity market in California, and the new cap-and-trade market.

The Utility meets customer demand for electricity from a variety of sources, including electricity generated from the Utility’s own generation facilities, electricity provided by third parties under power purchase agreements, and purchases on the wholesale electricity market.  The Utility must manage these sources using the principles of “least cost dispatch.”

The Utility enters into power purchase agreements, including contracts to purchase renewable energy, in compliance with a long-term procurement plan approved by the CPUC.  The Utility executes power purchase agreements following competitive requests for offers.  The Utility submits the winning contracts to the CPUC for approval and authorization to recover contract costs through rates.  There is a risk that the contractual prices the Utility is required to pay will become uneconomic in the future for a variety of reasons, including developments in alternative energy technology, increased self-generation by customers, an increase in distributed generation, and lower customer demand due to economic conditions or the loss of the Utility’s customers to other generation providers.  In particular, as the market for renewable energy develops in response to California’s renewable energy requirements, 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.  This could create a further risk that, despite original CPUC approval of the contracts, the CPUC would disallow contract costs in the future if the CPUC determines that the costs are unreasonably above market.  In addition, the CPUC could disallow procurement costs if the CPUC determined that the Utility incurred procurement costs that were not in compliance with its CPUC-approved procurement plan, or that the Utility did not prudently administer the power purchase agreements that were executed in compliance with the plan. The Utility also purchases energy through the day-ahead wholesale electricity market operated by the California Independent System Operator (“CAISO”).  The amount of electricity the Utility purchases on the wholesale market fluctuates due to a variety of factors, including, the level of electricity generated by the Utility’s own generation facilities, changes in customer demand, periodic expirations or terminations of power purchase contracts, the execution of  new power purchase contracts, fluctuation in the output of hydroelectric and other renewable power facilities owned or under contract by the Utility, and the implementation of new energy efficiency and demand response programs.  The market prices of electricity also fluctuate.  Although market mechanisms are designed to limit excessive prices, these market mechanisms could fail, or the related systems and software on which the market mechanisms rely may not perform as intended, which could result in excessive market prices. For example, during the 2000 and 2001 energy crisis, the market mechanism flaws in California’s newly established wholesale electricity market led to dramatically high market prices for electricity that the Utility was unable to recover through customer rates, ultimately causing the Utility to file a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code. 

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In addition, with the beginning of the first compliance period under the new California cap-and-trade regulations on January 1, 2013, electricity costs include associated cap-and-trade compliance costs.  Although some of these costs will be offset by revenues from the sale of emission allowances by the Utility on behalf of some classes of electricity customers, it is uncertain how the cap-and-trade market will develop in the future especially as the cap-and-trade compliance periods expand to cover other sources of GHG emissions and as other regional or federal cap-and-trade programs are adopted. 

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially affected if the Utility is unable to recover a material portion of the costs it incurs to deliver electricity to customers.

The completion of capital investment projects is subject to substantial risks, and the timing of the Utility’s capital expenditures and recovery of capital-related costs through rates, if at all, will directly affect net income.

The Utility’s ability to invest capital in its electric and natural gas businesses is subject to many risks, including risks related to obtaining regulatory approval, 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 or construct these projects also face many of these risks.  Changes in tax laws or policies, such as those relating “bonus” depreciation, may also affect when or whether a potential project is developed.  In addition, reduced forecasted demand for electricity and natural gas as a result of an economic slow-down, or other reasons, may also increase the risk that projects are deferred, abandoned, or cancelled.  Some of the Utility’s future capital investments may also be affected by evolving federal and state policies regarding the development of a “smart” electric transmission grid.

In addition, differences in the amount or timing of actual capital expenditures compared to the amount and timing of forecast capital expenditures authorized to be recovered through rates, can directly affect net income. Further, if capital expenditures are disallowed, the Utility would be required to write-off such expenses which could have a material effect on PG&E Corporation’s and the Utility’s financial condition and results of operations.

PG&E Corporation’s and the Utility’s financial results could be affected by the loss of Utility customers and decreased new customer growth due to municipalization, an increase in the number of community choice aggregators, increasing levels of “direct access,” and the development and integration of self-generation and distributed generation technologies, if the CPUC fails to adjust the Utility’s rates to reflect such events.

The Utility’s customers could bypass its distribution and transmission 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.  In addition, local government agencies could exercise their power of eminent domain to acquire the Utility’s facilities and use the facilities to provide utility service to their local residents and businesses.  The Utility may be unable to fully recover its investment in the distribution assets that it no longer owns.  The Utility’s natural gas transmission facilities could be 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 transmission and distribution system, or by customers who use and transport liquefied natural gas.

Alternatively, the Utility’s customers could become direct access customers who purchase electricity from alternative energy suppliers or they could become customers of governmental bodies registered as community choice aggregators to purchase and sell electricity for their residents and businesses.  Although the Utility is permitted to collect a non-bypassable charge for generation-related costs incurred on behalf of these customers, or distribution, metering, or other services it continues to provide, the fee may not be sufficient for the Utility to fully recover the costs to provide these services.  Furthermore, if the former customers return to receiving electricity supply from the Utility, the Utility could incur costs to meet their electricity needs that it may not be able to timely recover through rates or that it may not be able to recover at all.

In addition, increasing levels of self-generation of electricity by customers (primarily solar installations) and the use of customer net energy metering, which allows self-generating customers to receive bill credits for surplus power at the full retail rate, could put upward rate pressure on remaining customers.  Also, a confluence of technology-related cost declines and sustained federal or state subsidies make a combination of distributed generation and storage a viable, cost-effective alternative to the Utility’s bundled electric service which could further threaten the Utility’s ability to recover its generation, transmission, and distribution investments.

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If the CPUC fails to adjust the Utility’s rates to reflect the impact of changing loads, increasing self-generation and net energy metering, and the growth of distributed generation, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially adversely affected.

The operation of the Utility’s electricity and natural gas generation, transmission, and distribution facilities involve significant risks which, if they materialize, can adversely affect PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows, and the Utility’s insurance may not be sufficient to cover losses caused by an operating failure or catastrophic event.

The Utility owns and operates extensive electricity and natural gas facilities, including two nuclear generation units and an extensivehydroelectric generating system.  The Utility’s service territory covers approximately 70,000 square miles in northern and central California and is composed of diverse geographic regions with varying climates and weather conditions that create numerous operating challenges.  The Utility’s facilities are interconnected to the U.S. western electricity grid and numerous interstate and continental natural gas pipelines.  The Utility’s ability to earn its authorized rate of return depends on its ability to efficiently maintain and operate its facilities and provide electricity and natural gas services safely and reliably.  The maintenance and operation of the Utility’s facilities, and the facilities of third parties on which the Utility relies, involve numerous risks, including the risks discussed elsewhere in this section and those that arise from:

· the breakdown or failure of equipment,  electric transmission or distribution lines, or natural gas transmission and distribution pipelines, that can cause explosions, fires, or other catastrophic events;

· the failure of generation facilities to perform at expected or at contracted levels of output or efficiency;  

· the failure of a large dam or other major hydroelectric facility;

· the failure to take expeditious or sufficient action to mitigate operating conditions, facilities, or equipment, that the Utility has identified, or reasonably should have identified, as unsafe, which failure then leads to a catastrophic event;  

· severe weather events such as storms, tornadoes, floods, drought, earthquakes, tsunamis, wildland and other fires, pandemics, solar events, electromagnetic events, or other natural disasters;  

· operator or other human error;  

· fuel supply interruptions or the lack of available fuel which reduces or eliminates the Utility’s ability to provide electricity and/or natural gas service;  

·   the release of hazardous or toxic substances into the air or water;  

· use of new or unproven technologies;  

· cyber-attack; and  

· acts of terrorism, vandalism, or war.

The occurrence of any of these events could affect demand for electricity or natural gas; cause unplanned outages or reduce generating output which may require the Utility to incur costs to purchase replacement power; cause damage to the Utility’s assets or operations requiring the Utility to incur unplanned expenses to respond to emergencies and make repairs; damage the assets or operations of third parties on which the Utility relies; subject the Utility to claims by customers or third parties for damages to property, personal injury, or wrongful death, or subject the Utility to penalties.  These costs may not be recoverable through rates or insurance. Insurance, equipment warranties, or other contractual indemnification requirements may not be sufficient or effective to provide full or even partial recovery under all circumstances or against all hazards or liabilities to which the Utility may become subject.  An uninsured loss could have a material 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 or may not be available at all.

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The Utility’s operational and information systems on which it relies to conduct its business and serve customers could fail to function properly due to technological problems, a cyber-attack, acts of terrorism, severe weather, a solar event, an electromagnetic event, a natural disaster, the age and condition of information technology assets, human error, or other reasons, that could disrupt the Utility’s operations and cause the Utility to incur unanticipated losses and expense.

The operation of the Utility’s extensive electricity and natural gas systems rely on evolving information and operational technology systems and network infrastructures that are becoming more complex as new technologies and systems are implemented to modernize capabilities to safely and reliably deliver gas and electric services.  The Utility’s business is highly dependent on its ability to process and monitor, on a daily basis, a very large number of tasks and transactions, many of which are highly complex. The failure of the Utility’s information and operational systems and networks could significantly disrupt operations; result in public and employee safety lapse; result in outages; reduced generating output; damage to the Utility’s assets or operations or those of third parties; and subject the Utility to claims by customers or third parties, any of which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

The Utility’s systems, including its financial information, operational systems, advanced metering, and billing systems, require constant maintenance, modification, and updating, which can be costly and increases the risk of errors and malfunction.  Any disruptions or deficiencies in existing systems, or disruptions, delays or deficiencies in the modification or implementation of new systems, could result in increased costs, the inability to track or collect revenues, the diversion of management’s and employees’ attention and resources, and could negatively affect the effectiveness of the companies’ control environment, and/or the companies’ ability to timely file required regulatory reports. 

The Utility’s ability to measure customer energy usage and generate bills depends on the successful functioning of the advanced metering system.  The Utility relies on third party contractors and vendors to service, support, and maintain certain proprietary functional components of the advanced metering system.  If such a vendor or contractor ceased operations, if there was a contractual dispute or a failure to renew or negotiate the terms of a contract so that the Utility becomes unable to continue relying on such a third-party vendor or contractor, then the Utility could experience costs associated with disruption of billing and measurement operations and would incur costs as it seeks to find other replacement contractors or vendors or hire and train personnel to perform such services.

Despite implementation of security and mitigation measures, all of the Utility’s technology systems are vulnerable to disability or failures due to cyber-attacks, viruses, human errors, acts of war or terrorism, and other events.  If the Utility’s information technology systems or network infrastructure were to fail, the Utility might be unable to fulfill critical business functions and serve its customers, which could have a material effect on PG&E Corporation’s and the Utility’s financial conditions, results of operations, and cash flows.

In addition, in the ordinary course of its business, the Utility collects and retains sensitive information including personal identification information about customers and employees, customer energy usage, and other  information.  The theft, damage, or improper disclosure of sensitive electronic data can subject the Utility to penalties for violation of applicable privacy laws, subject the Utility to claims from third parties, and harm the Utility’s reputation.

The Utility’s success depends on the availability of the services of a qualified workforce and its ability to maintain satisfactory collective bargaining agreements which cover a substantial number of employees.  PG&E Corporation’s and the Utility’s results may suffer if the Utility is unable to attract and retain qualified personnel and senior management talent, or if prolonged labor disruptions occur.

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.  The majority of the Utility’s employees are covered by collective bargaining agreements with three unions.  The terms of these agreements affect the Utility’s labor costs.  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.  It is also possible that PG&E Corporation and the Utility may face challenges in attracting and retaining senior management talent especially if they are unable to restore the reputational harm generated by the negative publicity stemming from the San Bruno accident.  Any such occurrences could negatively impact PG&E Corporation’s and the Utility’s financial condition and results of operations.

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The operation and decommissioning of the Utility’s nuclear power plants expose it to potentially significant liabilities that it may not be able to recover from its insurance or other sources, and the Utility may incur significant capital expenditures and compliance costs that it may be unable to fully recover, adversely affecting PG&E Corporation’s and the Utility’s s financial conditions, results of operations, and cash flows.

The operation of the Utility’s nuclear generation facilities expose it to potentially significant liabilities from environmental, health and financial risks, such as risks relating to the storage, handling and disposal of spent nuclear fuel, the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act.  There are also significant uncertainties related to the regulatory, technological, and financial aspects of decommissioning nuclear generation plants when their licenses expire.  To reduce the Utility’s financial exposure to these risks, the Utility maintains insurance and manages decommissioning trusts that hold nuclear decommissioning charges collected through customer rates.  However, the costs or damages the Utility may incur in connection with the operation and decommissioning of its nuclear power plants could exceed the amount of the Utility’s insurance coverage and nuclear decommissioning trust assets.  The Utility has insurance coverage for property damages and business interruption losses, as well as coverage for acts of terrorism at its nuclear power plants as a member of Nuclear Electric Insurance Limited (“NEIL”), a mutual insurer owned by utilities with nuclear facilities.  NEIL provides coverage for both nuclear (meaning that nuclear material is released) and non-nuclear losses.  Due to multiple large non-nuclear losses in the industry, NEIL has notified the Utility and the other NEIL members that it will be significantly reducing its coverage for non-nuclear losses.  This change will affect the Utility beginning in April 2013.  While the Utility is seeking alternative insurance options, efforts to obtain additional coverage may not be successful.  Even if the Utility is able to obtain additional coverage, this future insurance coverage is not likely to be available at rates and on terms as favorable as the rates and terms of the Utility’s current NEIL insurance coverage.  If the Utility incurs losses that are either not covered by insurance or exceed the amount of insurance available, such losses could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

In addition, as an operator of the two operating nuclear reactor units at Diablo Canyon, 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.  (See Note 15 of the Notes to the Consolidated Financial Statements.)  The Utility’s ability to continue to operate its nuclear generation facilities also is subject to the availability of adequate nuclear fuel supplies on terms that the CPUC will find reasonable.

The NRC oversees the licensing, construction, and decommissioning of nuclear facilities and has broad authority to impose requirements relating to the maintenance and operation of nuclear facilities; the storage, handling and disposal of spent fuel; and the safety, radiological, environmental, and security aspects of nuclear facilities. The NRC has adopted regulations that are intended to protect nuclear facilities, nuclear facility employees, and the public from potential terrorist and other threats to the safety and security of nuclear operations, including threats posed by radiological sabotage or cyber-attack.  The Utility incurs substantial costs to comply with these regulations.  In addition, in March 2012, the NRC issued several orders to the owners of all U.S. operating nuclear reactors to implement the highest-priority recommendations issued by the NRC’s task force to incorporate the lessons learned from the March 2011 earthquake and tsunami that caused significant damage to the Fukushima-Dai-ichi nuclear facilities in Japan. The NRC may issue further orders to implement the recommendations, including facility-specific orders, which could require the Utility to incur additional costs.

The Utility has filed an application at the NRC to renew the operating licenses for the two operating units at Diablo Canyon which expire in 2024 and 2025.  In May 2011, after the Fukushima-Dai-ichi event, the NRC granted the Utility’s request to delay processing the Utility’s application until certain advanced seismic studies that the CPUC ordered the Utility to conduct were completed.  In November 2012, the California Coastal Commission denied the Utility’s request for permits to conduct some of these advanced studies.  The Utility is assessing whether it has sufficient seismic data without conducting the high energy off-shore studies or if other studies are needed.  It is uncertain when the Utility would request the NRC to resume the relicensing proceeding.  In order to receive renewed operating licenses, the Utility also must undergo a sufficiency review by the California Coastal Commission. The disposition of the Utility’s relicensing application also will be affected by the terms and timing of the NRC’s “waste confidence” decision regarding the environmental impacts of the storage of spent nuclear fuel.  The NRC’s original “waste confidence decision” in which the NRC found that spent nuclear fuel can be safely managed until a permanent off-site repository is established, was successfully challenged on the basis that the NRC’s environmental review was deficient.  In August 2012, the NRC ruled that it will not issue final decisions in licensing or re-licensing proceedings, including the Utility’s re-licensing application, until it had reconsidered the waste confidence issues. The NRC stated that it would consider all available options for resolving the waste confidence issue, which could include generic or site-specific NRC actions, or some combination of both.  The NRC has instructed its staff to develop and issue a new waste confidence decision and temporary storage rule by September 2014.

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The CPUC has authority to determine the rates the Utility can collect to recover its nuclear fuel, operating, maintenance, compliance, and decommissioning costs. The Utility also could incur significant expense to comply with regulations or orders the NRC may issue in the future to impose new safety requirements, to obtain license renewal, and to comply with federal and state policies and regulations applicable to the use of cooling water intake systems at generation facilities, such as Diablo Canyon. (See “Environmental Matters” above.)  The Utility expects that it would seek rate recovery of these additional costs.  The outcome of these rate proceedings at the CPUC can be influenced by public and political opposition to nuclear power.  If the Utility were unable to recover costs related to its nuclear facilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially affected.  The Utility may determine that it cannot comply with the new regulations or orders in a feasible and economic manner and voluntarily cease operations at Diablo Canyon.  Alternatively, the NRC may order the Utility to cease its nuclear operations until it can comply with new regulations or orders.  Further, the Utility could fail to obtain renewed operating licenses for Diablo Canyon requiring nuclear operations to cease when the current licenses expire in 2024 and 2025.

The Utility’s operations are subject to extensive environmental laws and changes in or liabilities under these laws could adversely affect PG&E Corporation’s and the Utility’s financial conditions, results of operations, and cash flows.

The Utility’s operations are subject to extensive federal, state, and local environmental laws, regulations, orders, relating to air quality, water quality and usage, remediation of hazardous wastes, and the protection and conservation of natural resources and wildlife.  The Utility can incur significant capital, operating, and other costs associated with compliance with these environmental statutes, rules, and regulations.  These costs can be difficult to forecast because the extent of contamination may be unknown. For example, the Utility’s costs to perform hydrostatic pressure testing of natural gas pipelines have included costs to obtain local agency and environmental permits to conduct the tests as well as costs to treat and dispose of the water used in the tests that becomes contaminated as the water travels through the pipes.  Further, even if the extent of contamination is known, remediation costs can be difficult to estimate due to many factors, including which remediation alternatives will be used, the applicable remediation levels, and the financial ability of other potentially responsible parties.  Environmental remediation costs could increase in the future as a result of new legislation, the current trend toward more stringent standards, and stricter and more expansive application of existing environmental regulations.  Failure to comply with these laws and regulations, or failure to comply with the terms of licenses or permits issued by environmental or regulatory agencies, could expose the Utility to claims by third parties or the imposition of civil or criminal penalties or other sanctions.

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, some of which the Utility no longer owns, include former manufactured gas plant 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.  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.  (See Note 15 to the Notes to the Consolidated Financial Statements for more information.)

The CPUC has authorized the Utility to recover its environmental remediation costs for certain sites through various ratemaking mechanisms. One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites without a reasonableness review. The CPUC may discontinue or change these ratemaking mechanisms in the future or the Utility may incur environmental costs that exceed amounts the CPUC has authorized the Utility to recover in rates.

Further, the CPUC has ruled that the Utility’s environmental costs for certain sites, such as the remediation costs associated with the Hinkley natural gas compressor site, are not recoverable through this ratemaking mechanism.  The Utility’s costs to remediate groundwater contamination near the Hinkley natural gas compressor site and to abate the effects of the contamination have had, and may continue to have, a material effect on PG&E Corporation’s and the Utility’s financial conditions, results of operations, and cash flows.  (See “Environmental Matters” above.)

The Utility’s future operations may be affected by climate change that may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

A report issued in 2012 by the EPA entitled,  “Climate Change Indicators in the United States, 2012” states that the increase of GHG emissions in the atmosphere is changing the fundamental measures of climate in the United States, including rising temperatures, shifting snow and rainfall patterns, and more extreme climate events.  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, the Utility will need to acquire 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 the Utility’s studies suggest 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 affected.

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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. In addition to the NRC requirements described above, these include meeting new renewable energy delivery requirements, resource adequacy requirements, federal electric reliability standards, customer billing, customer service, affiliate transactions, vegetation management, operating and maintenance practices, and safety and inspection practices.  The Utility is subject to penalties and sanctions for failure to comply with applicable statutes, regulations, rules, tariffs, and orders.

On January 1, 2012, the CPUC’s statutory authority to impose penalties increased from up to $20,000 per day, per violation, to up to $50,000 per day, per violation.  The CPUC has wide discretion to determine, based on the facts and circumstances, whether a single violation or multiple violations were committed and to determine the length of time a violation existed for purposes of calculating the amount of penalties.  The CPUC has delegated authority to the SED to levy citations and impose penalties for violations of certain regulations related to the safety of natural gas facilities and utilities’ natural gas operating practices.  Like the CPUC, the SED has discretion to determine how to count the number of violations, but the delegated authority requires the SED to assess the maximum statutory fine per violation.  (For a discussion of pending investigations and potential enforcement proceedings, see MD&A “Natural Gas Matters” above.) There is a risk that the CPUC could delegate additional enforcement authority to its staff or that legislation could be enacted to require the CPUC to further delegate enforcement authority.

In addition, the federal Pipeline and Hazardous Materials Safety Administration can impose penalties for violation of federal pipeline safety regulations in amounts that range from $100,000 to $200,000 for an individual violation and from $1 million to $2 million for a series of violations.

The Utility must comply with federal electric reliability standards that are set by the North American Electric Reliability Corporation and approved by the FERC.  These standards relate to maintenance, training, operations, planning, vegetation management, facility ratings, and other subjects.  These standards are designed to maintain the reliability of the nation’s bulk power system and to protect the system against potential disruptions from cyber-attacks and physical security breaches.  The FERC can impose penalties (up to $1 million per day, per violation) for failure to comply with these mandatory electric reliability standards.  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, statutes, regulations, rules, tariffs, and orders, or their interpretation and application, may become more stringent and difficult to comply with in the future. 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 flows would be materially 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 for one or more of the Utility’s hydroelectric generation facilities or assets, 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.

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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 affected.

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 has recorded an asset retirement obligation related to decommissioning its nuclear facilities based on various estimates and assumptions. Changes in these estimates and assumptions can materially affect the amount of the recorded asset retirement obligation. (See Note 2 of the Notes to the Consolidated Financial Statements for a discussion of the increase in the recorded asset retirement obligation to reflect increased estimated decommissioning costs.)

The CPUC has authorized the Utility to recover 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 also can negatively affect net income.

PG&E Corporation’s and the Utility’s financial statements reflect various estimates, assumptions, and values and are prepared in accordance with applicable accounting rules, standards, policies, guidance, and  interpretations, including those related to regulatory assets and liabilities.  Changes to these estimates, assumptions, values, and accounting rules, or changes in the application of these rules, 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 Notes 1 and 2 of the Notes to the Consolidated Financial Statements and “Critical Accounting Policies” above.)  If the information on which the estimates and assumptions are based proves 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 or results of operations.

As a regulated entity, the Utility’s rates are designed to recover the costs of providing service.  The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates.  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.  At December 31, 2012, PG&E Corporation and the Utility reported regulatory assets of $8.3 billion and regulatory liabilities of $6.1 billion.  (See Note 3 of the Notes to the Consolidated Financial Statements.)  Management believes that currently available facts support the continued application of regulatory accounting and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment.   Since the San Bruno accident in September 2010, the Utility has recorded cumulative charges of approximately $1.83 billion related to its natural gas operations that are not recoverable through rates.  To the extent that rates are not set at a level that allows the Utility to recover the cost of providing service and a reasonable return on its investment in future periods, the Utility may be required to discontinue the application of regulatory accounting for portions of its operations.  If that occurs, the related regulatory assets and liabilities would be charged against income in the period in which that determination was made and could have a material impact on PG&E Corporation’s and the Utility’s future financial condition and results of operations.

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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.  The Utility’s ability to pay common stock dividends is constrained by regulatory requirements, including that the Utility maintain its authorized capital structure with an average 52% equity component.  Further, the CPUC could adopt the SED’s financial recommendations made in its January 12, 2012 report on the San Bruno accident, including that the Utility “should target retained earnings towards safety improvements before providing dividends, especially if the Utility’s ROE exceeds the level set in a GRC.” PG&E Corporation’s and the Utility’s ability to pay dividends also could be affected by financial covenants contained in their respective credit agreements that require each company to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%.  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 Utility’s financial condition will be affected by the amount of costs the Utility incurs that it is not allowed to recover through rates, the amount of third-party losses it is unable to recover through insurance, and the amount of penalties the Utility incurs in connection with the pending investigations and future citations for self-reported violations.  After considering these impacts, 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, or both, any of which could materially restrict PG&E Corporation’s ability to pay principal and interest on its outstanding debt or pay its common stock dividend, meet other obligations, or execute its business strategy.  Further, laws or regulations could be enacted or adopted in the future that could impose additional financial or other restrictions or requirements pertaining to transactions between a holding company and its regulated subsidiaries.

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows will be affected by their ability to continue accessing the capital markets and by the terms of debt and equity financings.

The Utility relies on access to capital and credit markets as significant sources of liquidity to fund capital expenditures, pay principal and interest on its debt, provide collateral to support its natural gas and electricity procurement hedging contracts, and fund other operations requirements that are not satisfied by operating cash flows.  See the discussion of the Utility’s future financing needs above in “Liquidity and Financial Resources.”  PG&E Corporation relies on independent access to the capital and credit markets to fund its operations, make capital expenditures, and contribute equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure, if funds received from the Utility (in the form of dividends or share repurchases) are insufficient to meet such needs.  Following the San Bruno accident, PG&E Corporation has issued a material amount of equity to fund its equity contributions to the Utility as the Utility has incurred costs and expenses it cannot recover through rates.

PG&E Corporation forecasts that it will continue to issue additional material amounts of equity as the Utility continues to incur costs that it cannot recover through rates, such as costs under its pipeline safety enhancement plan, to improve electricity and natural gas operations, and to pay penalties. PG&E Corporation may also be required to access the capital markets when the Utility is successful in selling long-term debt so that PG&E Corporation can contribute equity to the Utility as needed to maintain the Utility’s authorized capital structure.

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 the amount of penalties imposed on the Utility in connection with the matters described above under “Natural Gas Maters;” changes in their credit ratings; changes in the federal or state regulatory environment affecting energy companies generally or PG&E Corporation and the Utility in particular; the overall health of the energy industry; volatility in electricity or natural gas prices; disruptions, uncertainty or volatility in the capital and credit markets; and general economic and market conditions.  If PG&E Corporation’s or the Utility’s credit ratings were downgraded to below investment grade, their ability to access the capital and credit markets could be negatively affected and could result in higher borrowing costs, fewer financing options, including reduced access to the commercial paper market, additional collateral posting requirements, which in turn could affect liquidity and lead to an increased financing need.

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 seek these funds from the capital or credit markets.  To maintain PG&E Corporation’s dividend level in these circumstances, PG&E Corporation would be further required to access the capital or credit markets.  PG&E Corporation may need to decrease or discontinue its common stock dividend if it is unable to access the capital or credit markets on reasonable terms.

49

PG&E Corporation

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

	Year ended December 31,
	2012			2011			2010
Operating Revenues
Electric	$	12,019		$	11,606		$	10,645
Natural gas		3,021			3,350			3,196
Total operating revenues		15,040			14,956			13,841
Operating Expenses
Cost of electricity		4,162			4,016			3,898
Cost of natural gas		861			1,317			1,291
Operating and maintenance		6,052			5,466			4,439
Depreciation, amortization, and decommissioning		2,272			2,215			1,905
Total operating expenses		13,347			13,014			11,533
Operating Income		1,693			1,942			2,308
Interest income		7			7			9
Interest expense		(703	)		(700	)		(684	)
Other income, net		70			49			27
Income Before Income Taxes		1,067			1,298			1,660
Income tax provision		237			440			547
Net Income		830			858			1,113
Preferred stock dividend requirement of subsidiary		14			14			14
Income Available for Common Shareholders	$	816		$	844		$	1,099
Weighted Average Common Shares Outstanding, Basic		424			401			382
Weighted Average Common Shares Outstanding, Diluted		425			402			392
Net Earnings Per Common Share, Basic	$	1.92		$	2.10		$	2.86
Net Earnings Per Common Share, Diluted	$	1.92		$	2.10		$	2.82
Dividends Declared Per Common Share	$	1.82		$	1.82		$	1.82
See accompanying Notes to the Consolidated Financial Statements.

50

PG&E Corporation

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year ended December 31,
(in millions)	2012		2011			2010
Net Income	$	830	$	858		$	1,113
Other Comprehensive Income
Pension and other postretirement benefit plans
Unrecognized prior service credit (cost) (net of income tax
of $14, $24, and $20 in 2012, 2011, and 2010, respectively)		17		36			(29	)
Unrecognized net gain (loss) (net of income tax of $20, $452,
and $73 in 2012 , 2011, and 2010, respectively)		31		(655	)		(110	)
Unrecognized net transition obligation (net of income
tax of $8 in 2012, and $11 in 2011 and 2010, respectively)		16		15			15
Transfer to regulatory account (net of income tax of
$30, $408, and $57 in 2012, 2011, and 2010, respectively)		44		593			82
Other (net of income tax of $3 in 2012)		4		-			-
Total other comprehensive income (loss)		112		(11	)		(42	)
Comprehensive Income		942		847			1,071
Preferred stock dividend requirement of subsidiary		14		14			14
Comprehensive Income Attributable to Common Shareholders	$	928	$	833		$	1,057
See accompanying Notes to the Consolidated Financial Statements.

51

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2012			2011
ASSETS
Current Assets
Cash and cash equivalents	$	401		$	513
Restricted cash ($0 and $51 related to energy recovery bonds at
December 31, 2012 and 2011, respectively)		330			380
Accounts receivable
Customers (net of allowance for doubtful accounts of $87 and $81 at
December 31, 2012 and 2011, respectively)		937			992
Accrued unbilled revenue		761			763
Regulatory balancing accounts		936			1,082
Other		365			839
Regulatory assets ($0 and $336 related to energy recovery bonds at
December 31, 2012 and 2011, respectively)		564			1,090
Inventories
Gas stored underground and fuel oil		135			159
Materials and supplies		309			261
Income taxes receivable		211			183
Other		172			218
Total current assets		5,121			6,480
Property, Plant, and Equipment
Electric		39,701			35,851
Gas		12,571			11,931
Construction work in progress		1,894			1,770
Other		1			15
Total property, plant, and equipment		54,167			49,567
Accumulated depreciation		(16,644	)		(15,912	)
Net property, plant, and equipment		37,523			33,655
Other Noncurrent Assets
Regulatory assets		6,809			6,506
Nuclear decommissioning trusts		2,161			2,041
Income taxes receivable		176			386
Other		659			682
Total other noncurrent assets		9,805			9,615
TOTAL ASSETS	$	52,449		$	49,750
See accompanying Notes to the Consolidated Financial Statements.

52

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2012			2011
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	492		$	1,647
Long-term debt, classified as current		400			50
Energy recovery bonds, classified as current		-			423
Accounts payable
Trade creditors		1,241			1,177
Disputed claims and customer refunds		157			673
Regulatory balancing accounts		634			374
Other		444			420
Interest payable		870			843
Income taxes payable		6			110
Deferred income taxes		-			196
Other		2,012			1,836
Total current liabilities		6,256			7,749
Noncurrent Liabilities
Long-term debt		12,517			11,766
Regulatory liabilities		5,088			4,733
Pension and other postretirement benefits		3,575			3,396
Asset retirement obligations		2,919			1,609
Deferred income taxes		6,748			6,008
Other		2,020			2,136
Total noncurrent liabilities		32,867			29,648
Commitments and Contingencies (Note 15)
Equity
Shareholders' Equity
Preferred stock		-			-
Common stock, no par value, authorized 800,000,000 shares,
430,718,293 shares outstanding at December 31, 2012 and
412,257,082 shares outstanding at December 31, 2011		8,428			7,602
Reinvested earnings		4,747			4,712
Accumulated other comprehensive loss		(101	)		(213	)
Total shareholders' equity		13,074			12,101
Noncontrolling Interest - Preferred Stock of Subsidiary		252			252
Total equity		13,326			12,353
TOTAL LIABILITIES AND EQUITY	$	52,449		$	49,750
See accompanying Notes to the Consolidated Financial Statements.

53

PG&E Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2012			2011			2010
Cash Flows from Operating Activities
Net income	$	830		$	858		$	1,113
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		2,272			2,215			1,905
Allowance for equity funds used during construction		(107	)		(87	)		(110	)
Deferred income taxes and tax credits, net		648			544			756
Disallowed capital expenditures		353			-			36
Other		290			326			257
Effect of changes in operating assets and liabilities:
Accounts receivable		(40	)		(288	)		(44	)
Inventories		(24	)		(63	)		(43	)
Accounts payable		(4	)		65			48
Income taxes receivable/payable		(132	)		(103	)		(78	)
Other current assets and liabilities		262			23			111
Regulatory assets, liabilities, and balancing accounts, net		291			(100	)		(394	)
Other noncurrent assets and liabilities		243			349			(351	)
Net cash provided by operating activities		4,882			3,739			3,206
Cash Flows from Investing Activities
Capital expenditures		(4,624	)		(4,038	)		(3,802	)
Decrease in restricted cash		50			200			66
Proceeds from sales and maturities of nuclear decommissioning
trust investments		1,133			1,928			1,405
Purchases of nuclear decommissioning trust investments		(1,189	)		(1,963	)		(1,456	)
Other		104			(113	)		(70	)
Net cash used in investing activities		(4,526	)		(3,986	)		(3,857	)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities		120			358			490
Repayments under revolving credit facilities		-			(358	)		(490	)
Net issuances (repayments) of commercial paper, net of discount
of $3 in 2012, $4 in 2011, and $3 in 2010		(1,021	)		782			267
Proceeds from issuance of short-term debt, net of issuance costs
of $1 in 2010		-			250			249
Proceeds from issuance of long-term debt, net of premium,
discount, and issuance costs of $13 in 2012, $8 in 2011, and $23
in 2010		1,137			792			1,327
Short-term debt matured		(250	)		(250	)		(500	)
Long-term debt matured or repurchased		(50	)		(700	)		(95	)
Energy recovery bonds matured		(423	)		(404	)		(386	)
Common stock issued		751			662			303
Common stock dividends paid		(746	)		(704	)		(662	)
Other		14			41			(88	)
Net cash provided by (used in) financing activities		(468	)		469			415
Net change in cash and cash equivalents		(112	)		222			(236	)
Cash and cash equivalents at January 1		513			291			527
Cash and cash equivalents at December 31	$	401		$	513		$	291
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(594	)	$	(647	)	$	(627	)
Income taxes, net		114			(42	)		(135	)
Supplemental disclosures of noncash investing and financing
activities
Common stock dividends declared but not yet paid	$	196		$	188		$	183
Capital expenditures financed through accounts payable		362			308			364
Noncash common stock issuances		22			24			265
Terminated capital leases		136			-			-
See accompanying Notes to the Consolidated Financial Statements.

54

PG&E Corporation

CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)

															Non
									Accumulated						controlling
									Other						Interest -
	Common		Common						Comprehensive			Total			Preferred
	Stock		Stock			Reinvested			Income			Shareholders'			Stock of		Total
	Shares		Amount			Earnings			(Loss)			Equity			Subsidiary		Equity
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
Other comprehensive loss		-		-			-			(42	)		(42	)		-		(42	)
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
Net income		-		-			858			-			858			-		858
Other comprehensive loss		-		-			-			(11	)		(11	)		-		(11	)
Common stock issued, net		17,029,877		686			-			-			686			-		686
Stock-based compensation amortization		-		37			-			-			37			-		37
Common stock dividends declared		-		-			(738	)		-			(738	)		-		(738	)
Tax benefit from employee stock plans		-		1			-			-			1			-		1
Preferred stock dividend requirement of
subsidiary		-		-			(14	)		-			(14	)		-		(14	)
Balance at December 31, 2011		412,257,082		7,602			4,712			(213	)		12,101			252		12,353
Net income		-		-			830			-			830			-		830
Other comprehensive income		-		-			-			112			112			-		112
Common stock issued, net		18,461,211		773			-			-			773			-		773
Stock-based compensation amortization		-		52			-			-			52			-		52
Common stock dividends declared		-		-			(781	)		-			(781	)		-		(781	)
Tax benefit from employee stock plans		-		1			-			-			1			-		1
Preferred stock dividend requirement of
subsidiary		-		-			(14	)		-			(14	)		-		(14	)
Balance at December 31, 2012		430,718,293	$	8,428		$	4,747		$	(101	)	$	13,074		$	252	$	13,326
See accompanying Notes to the Consolidated Financial Statements.

55

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

	Year ended December 31,
	2012			2011			2010
Operating Revenues
Electric	$	12,014		$	11,601		$	10,644
Natural gas		3,021			3,350			3,196
Total operating revenues		15,035			14,951			13,840
Operating Expenses
Cost of electricity		4,162			4,016			3,898
Cost of natural gas		861			1,317			1,291
Operating and maintenance		6,045			5,459			4,432
Depreciation, amortization, and decommissioning		2,272			2,215			1,905
Total operating expenses		13,340			13,007			11,526
Operating Income		1,695			1,944			2,314
Interest income		6			5			9
Interest expense		(680	)		(677	)		(650	)
Other income, net		88			53			22
Income Before Income Taxes		1,109			1,325			1,695
Income tax provision		298			480			574
Net Income		811			845			1,121
Preferred stock dividend requirement		14			14			14
Income Available for Common Stock	$	797		$	831		$	1,107
See accompanying Notes to the Consolidated Financial Statements.

56

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year ended December 31,
(in millions)	2012		2011			2010
Net Income	$	811	$	845		$	1,121
Other Comprehensive Income
Pension and other postretirement benefit plans
Unrecognized prior service credit (cost) (net of income tax
of $13, $24, and $21 in 2012, 2011, and 2010, respectively)		16		36			(30	)
Unrecognized net gain (loss) (net of income tax of $22, $447,
and $74 in 2012, 2011, and 2010, respectively)		33		(651	)		(108	)
Unrecognized net transition obligation (net of income tax of
$8 in 2012, and $11 in 2011 and 2010, respectively)		16		15			15
Transfer to regulatory account (net of income tax of
$30, $408, and $57 in 2012, 2011, and 2010, respectively)		44		593			82
Total other comprehensive income (loss)		109		(7	)		(41	)
Comprehensive Income	$	920	$	838		$	1,080
See accompanying Notes to the Consolidated Financial Statements.

57

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2012			2011
ASSETS
Current Assets
Cash and cash equivalents	$	194		$	304
Restricted cash ($0 and $51 related to energy recovery bonds at
December 31, 2012 and 2011, respectively)		330			380
Accounts receivable
Customers (net of allowance for doubtful accounts of $87 and $81 at
December 31, 2012 and 2011, respectively)		937			992
Accrued unbilled revenue		761			763
Regulatory balancing accounts		936			1,082
Other		366			840
Regulatory assets ($0 and $336 related to energy recovery bonds at
December 31, 2012 and 2011, respectively)		564			1,090
Inventories
Gas stored underground and fuel oil		135			159
Materials and supplies		309			261
Income taxes receivable		186			242
Other		160			213
Total current assets		4,878			6,326
Property, Plant, and Equipment
Electric		39,701			35,851
Gas		12,571			11,931
Construction work in progress		1,894			1,770
Total property, plant, and equipment		54,166			49,552
Accumulated depreciation		(16,643	)		(15,898	)
Net property, plant, and equipment		37,523			33,654
Other Noncurrent Assets
Regulatory assets		6,809			6,506
Nuclear decommissioning trusts		2,161			2,041
Income taxes receivable		171			384
Other		381			331
Total other noncurrent assets		9,522			9,262
TOTAL ASSETS	$	51,923		$	49,242
See accompanying Notes to the Consolidated Financial Statements.

58

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2012			2011
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	372		$	1,647
Long-term debt, classified as current		400			50
Energy recovery bonds, classified as current		-			423
Accounts payable
Trade creditors		1,241			1,177
Disputed claims and customer refunds		157			673
Regulatory balancing accounts		634			374
Other		419			417
Interest payable		865			838
Income taxes payable		12			118
Deferred income taxes		-			199
Other		1,794			1,628
Total current liabilities		5,894			7,544
Noncurrent Liabilities
Long-term debt		12,167			11,417
Regulatory liabilities		5,088			4,733
Pension and other postretirement benefits		3,497			3,325
Asset retirement obligations		2,919			1,609
Deferred income taxes		6,939			6,160
Other		1,959			2,070
Total noncurrent liabilities		32,569			29,314
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, 2012 and 2011		1,322			1,322
Additional paid-in capital		4,682			3,796
Reinvested earnings		7,291			7,210
Accumulated other comprehensive loss		(93	)		(202	)
Total shareholders' equity		13,460			12,384
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	51,923		$	49,242
See accompanying Notes to the Consolidated Financial Statements.

59

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2012			2011			2010
Cash Flows from Operating Activities
Net income	$	811		$	845		$	1,121
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		2,272			2,215			1,905
Allowance for equity funds used during construction		(107	)		(87	)		(110	)
Deferred income taxes and tax credits, net		684			582			762
Disallowed capital expenditures		353			-			36
Other		236			289			221
Effect of changes in operating assets and liabilities:
Accounts receivable		(40	)		(227	)		(105	)
Inventories		(24	)		(63	)		(43	)
Accounts payable		(26	)		51			109
Income taxes receivable/payable		(50	)		(192	)		(58	)
Other current assets and liabilities		272			36			123
Regulatory assets, liabilities, and balancing accounts, net		291			(100	)		(394	)
Other noncurrent assets and liabilities		256			414			(331	)
Net cash provided by operating activities		4,928			3,763			3,236
Cash Flows from Investing Activities
Capital expenditures		(4,624	)		(4,038	)		(3,802	)
Decrease in restricted cash		50			200			66
Proceeds from sales and maturities of nuclear decommissioning
trust investments		1,133			1,928			1,405
Purchases of nuclear decommissioning trust investments		(1,189	)		(1,963	)		(1,456	)
Other		16			14			19
Net cash used in investing activities		(4,614	)		(3,859	)		(3,768	)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities		-			208			400
Repayments under revolving credit facilities		-			(208	)		(400	)
Net issuances (repayments) of commercial paper, net of discount
of $3 in 2012, $4 in 2011, and $3 in 2010		(1,021	)		782			267
Proceeds from issuance of short-term debt, net of issuance costs of
$1 in 2010		-			250			249
Proceeds from issuance of long-term debt, net of premium,
discount, and issuance costs of $13 in 2012, $8 in 2011, and $23
in 2010		1,137			792			1,327
Short-term debt matured		(250	)		(250	)		(500	)
Long-term debt matured or repurchased		(50	)		(700	)		(95	)
Energy recovery bonds matured		(423	)		(404	)		(386	)
Preferred stock dividends paid		(14	)		(14	)		(14	)
Common stock dividends paid		(716	)		(716	)		(716	)
Equity contribution		885			555			190
Other		28			54			(73	)
Net cash provided by (used in) financing activities		(424	)		349			249
Net change in cash and cash equivalents		(110	)		253			(283	)
Cash and cash equivalents at January 1		304			51			334
Cash and cash equivalents at December 31	$	194		$	304		$	51
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(574	)	$	(627	)	$	(595	)
Income taxes, net		174			(50	)		(171	)
Supplemental disclosures of noncash investing and financing
activities
Capital expenditures financed through accounts payable	$	362		$	308		$	364
Terminated capital leases		136			-			-
See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in millions)

											Accumulated
					Additional						Other			Total
	Preferred		Common		Paid-in			Reinvested			Comprehensive			Shareholders'
	Stock		Stock		Capital			Earnings			Income (Loss)			Equity
Balance at December 31, 2009	$	258	$	1,322	$	3,055		$	6,704		$	(154	)	$	11,185
Net income		-		-		-			1,121			-			1,121
Other comprehensive loss		-		-		-			-			(41	)		(41	)
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
Net income		-		-		-			845			-			845
Other comprehensive loss		-		-		-			-			(7	)		(7	)
Equity contribution		-		-		555			-			-			555
Common stock dividend		-		-		-			(716	)		-			(716	)
Preferred stock dividend		-		-		-			(14	)		-			(14	)
Balance at December 31, 2011		258		1,322		3,796			7,210			(202	)		12,384
Net income		-		-		-			811			-			811
Other comprehensive income		-		-		-			-			109			109
Equity contribution		-		-		885			-			-			885
Tax benefit from employee stock plans		-		-		1			-			-			1
Common stock dividend		-		-		-			(716	)		-			(716	)
Preferred stock dividend		-		-		-			(14	)		-			(14	)
Balance at December 31, 2012	$	258	$	1,322	$	4,682		$	7,291		$	(93	)	$	13,460
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 that conducts its business 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 primarily regulated 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 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.  PG&E Corporation and the Utility operate in one segment.

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, legal and regulatory contingencies, environmental remediation liabilities, asset retirement obligations (“ARO”), and pension and other postretirement benefit plans obligations.  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 and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.

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.)

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.  Inventories include natural gas stored underground and materials and supplies.  Natural gas stored underground represents purchases that are recorded to inventory and then expensed at weighted average cost when withdrawn and distributed to customers or used in electric generation.  Materials and supplies are recorded to inventory when purchased and then expensed or capitalized to plant, as appropriate, when consumed or installed.

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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 estimated useful lives and balances of its property, plant, and equipment were as follows:

	Estimated Useful	Balance at December 31,
(in millions, except estimated useful lives)	Lives (years)	2012			2011
Electricity generating facilities (1)	10 to 100	$	8,253		$	6,488
Electricity distribution facilities	10 to 55		23,767			22,395
Electricity transmission	10 to 70		7,681			6,968
Natural gas distribution facilities	20 to 53		8,257			7,832
Natural gas transportation and storage	5 to 48		4,314			4,099
Construction work in progress			1,894			1,770
Total property, plant, and equipment			54,166			49,552
Accumulated depreciation			(16,643	)		(15,898	)
Net property, plant, and equipment		$	37,523		$	33,654

(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.)

Depreciation 

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment in a particular class of property.  This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment.  The Utility’s composite depreciation rates were 3.63% in 2012, 3.67% in 2011, and 3.38% in 2010.

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 against 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.

AFUDC

AFUDC is a method used to compensate the Utility for the estimated cost of debt (i.e., interest) and equity funds used to finance regulated plant additions and is capitalized as part of the cost of construction.  AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service.  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 $49 million and $107 million during 2012, $40 million and $87 million during 2011, and $50 million and $110 million during 2010, related to debt and equity, respectively.

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 regulatory assets, 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 in which 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’s ability to recover the revenue requirements that have been authorized by the CPUC in a general rate case (“GRC”) and a gas transmission and storage rate case (“GT&S”) does not depend on the volume of the Utility’s sales of electricity and natural gas services. The Utility’s recovery of a significant portion of its authorized revenue requirements through rates is independent, or “decoupled,” from the volume of electricity and natural gas sales.

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The Utility records differences between actual customer billings and the Utility’s authorized revenue requirement, as well as differences between incurred costs and customer billings or authorized revenue meant to recover those costs.  To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account asset or liability, respectively and the differences do not have an impact on net income.  For further discussion, 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 terms ranging from 19 to 53 years.  The gross carrying amount of intangible assets was $110 million at December 31, 2012 and $112 million at December 31, 2011.  The accumulated amortization was $49 million at December 31, 2012 and $47 million at December 31, 2011.

The Utility’s amortization expense related to intangible assets was $2 million in 2012, $3 million in 2011, and $4 million in 2010.  The estimated annual amortization expense for 2013 through 2017 based on the December 31, 2012 intangible assets balance is $3 million.  Intangible assets are recorded to other noncurrent assets – other in the Consolidated Balance Sheets.

Asset Retirement Obligations

PG&E Corporation and the Utility record an ARO at discounted fair value in the period in which the obligation is incurred if the discounted 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 ARO is accreted to its present value.  PG&E Corporation and the Utility also record an ARO if a legal obligation to perform an asset removal exists and can be reasonably estimated, but performance is conditional upon a future event.  The Utility recognizes timing differences between the recognition of costs and the costs recovered through the ratemaking process as regulatory assets or liabilities.  (See Note 3 below.)  The Utility has an ARO primarily for its nuclear generation facilities, certain fossil fuel-fired generation facilities, and gas transmission system assets.

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceedings (“NDCTP”) conducted by the CPUC.  In December 2012, the Utility submitted its updated decommissioning cost estimate with the CPUC.  The estimated undiscounted cost to decommission the Utility’s nuclear power plants increased by $1.4 billion due to higher spent nuclear fuel disposal costs and an increase in the scope of work.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear generation facilities.  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.  The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.  A significant portion of the increase in decommissioning cost estimates is due to the need to develop on-site storage for spent nuclear fuel because the federal government has failed to meet its obligation to develop a permanent repository for the disposal of nuclear waste from nuclear facilities in the United States.  The Utility expects that it will recover its future on-site storage costs from the federal government.  The Utility already has recovered $266 million for spent nuclear fuel costs incurred through 2010. (See “Spent Nuclear Fuel Storage Proceedings” in Note 15 below).  Recovered amounts will be refunded to customers through rates.  In its 2012 NDCTP application, the Utility requested that the CPUC issue a final decision by the end of 2013.

The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear generation facilities was approximately $3.5 billion at December 31, 2012 and $2.3 billion at December 31, 2011, as filed in the 2012 and 2009 NDCTPs, respectively.  In future dollars, the estimated nuclear decommissioning cost is approximately $6.1 billion and $4.4 billion, respectively.  These estimates are based on the 2012 and 2009 decommissioning cost studies, respectively, and are prepared in accordance with CPUC requirements.  The estimated nuclear decommissioning cost in future dollars is discounted for GAAP purposes and recognized as an ARO on the Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued in accordance with GAAP was $2.5 billion at December 31, 2012 and $1.2 billion at December 31, 2011.

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A reconciliation of the changes in the ARO liability is as follows:

(in millions)
ARO liability at December 31, 2010	$	1,586
Revision in estimated cash flows		10
Accretion		100
Liabilities settled		(87	)
ARO liability at December 31, 2011		1,609
Revision in estimated cash flows		1,301
Accretion		101
Liabilities settled		(92	)
ARO liability at December 31, 2012	$	2,919

The Utility has identified the following AROs for which a reasonable estimate of fair value could not be made.  As a result, the Utility has not recorded a liability related to these AROs:

·Restoration of land to its pre-use condition under the terms of certain land rights agreements.  Land rights will be maintained for the foreseeable future, and therefore, the Utility cannot reasonably estimate the settlement date(s) or range of settlement dates for the obligations associated with these assets;

·Removal and proper disposal of lead-based paint contained in some Utility facilities.  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 obligations; and

·Removal of certain communications equipment from leased property, and retirement activities associated with substation and certain hydroelectric facilities.  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, expected to be economically beneficial.  Therefore, the settlement date(s) cannot be reasonably estimated at this time.

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge to net income when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.  During 2012, the Utility recorded a $353 million charge to net income for capital expenditures incurred in connection with its pipeline safety enhancement plan that were either specifically disallowed or that are forecasted to exceed the CPUC’s authorized levels.  (See “CPUC Gas Safety Rulemaking Proceeding” in Note 15 below).  No material disallowance losses were recorded in 2011 and $36 million in disallowance losses were recorded in 2010.

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 $163 million and $186 million at December 31, 2012 and 2011, respectively.  The amortization expense related to this loss was $23 million in 2012, $18 million in 2011, and $23 million in 2010.  Deferred gains and losses on debt extinguishments are recorded to current assets – regulatory assets 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.

Revenue Recognition

The Utility recognizes revenues as electricity and natural gas services are delivered, and includes amounts for services rendered but not yet billed at the end of the period.

The CPUC authorizes most of the Utility’s revenue requirements in its GRC and its GT&S, which generally occur every three years.  The Utility’s ability to recover revenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility’s sales of electricity and natural gas services.  The Utility recognizes revenues once they have been authorized for rate recovery, amounts are objectively determinable and probable of recovery, and amounts will be collected within 24 months.  Generally, the revenue recognition criteria are met ratably over the year.  (See Note 3 below.)

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The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose, demand response, and customer energy efficiency programs.  Generally, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred.

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.

The Utility’s revenues and net income also are affected by incentive ratemaking mechanisms that adjust rates depending on the extent to which the Utility meets certain performance criteria.

Income Taxes

PG&E Corporation and the Utility use the liability method of accounting for income taxes.  Income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period actual tax expense in addition to calculating deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as depreciation, and are reported within the PG&E Corporation and Utility’s balance sheets.  (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.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit.

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.

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 generation facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.

The Utility classifies its investments held in the nuclear decommissioning trusts as “available-for-sale.”  Since 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 its 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 through rates.  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.

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Accounting for Derivatives

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 probable of future recovery through regulated rates, are deferred and recorded in regulatory accounts.

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 which qualify for the normal purchase and sales exception are not reflected in the Consolidated Balance Sheets at fair value, but are accounted for under the accrual method of accounting.  Therefore, expenses are recognized as incurred.

PG&E Corporation and the Utility offset 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 and the intention to offset exist.  (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.)

Variable Interest Entities

PG&E Corporation and the Utility are required to consolidate the financial results of any entities that they control.  In most cases, control can be determined based on majority ownership or voting interests.  However, there are certain entities known as variable interest entities (“VIEs”) for which control is difficult to discern based on ownership or voting interests alone.  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 in a VIE if it has the obligation to absorb expected losses or the right to receive expected gains that could potentially be significant to the VIE and if it has any decision-making rights associated with the activities that are most significant to the VIE’s economic performance, including the power to design the VIE.  An enterprise that has a controlling financial interest in a VIE is known as the VIE’s primary beneficiary and is required to consolidate the VIE.

In determining whether consolidation of a particular entity is required, PG&E Corporation and the Utility first evaluate whether the entity is a VIE.  If the entity is a VIE, PG&E Corporation and the Utility use a qualitative approach to determine if either is the primary beneficiary of the VIE.

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility subject to the terms of a power purchase agreement.  In determining whether the Utility is the primary beneficiary of any of these VIEs, it assesses whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement.  This assessment includes an evaluation of how the risks and rewards associated with the power plant’s activities are absorbed by variable interest holders, as well as an analysis of the variability in the VIE’s gross margin and the impact of the power purchase agreement on the gross margin.  Under each of these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE.  The Utility does 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 any decision-making rights associated with the design of any VIEs, nor does the Utility have the power to direct the activities that are most significant to the economic performance of any VIEs such as dispatch rights, operating and maintenance activities, or re-marketing activities of the power plant after the termination of any VIE’s power purchase agreement with the Utility.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2012, it did not consolidate any of them.

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The Utility continued to consolidate the financial results of PG&E Energy Recovery Funding LLC (“PERF”), a VIE, at December 31, 2012, since the Utility is the primary beneficiary of PERF.  PERF was formed in 2005 as a wholly owned subsidiary of the Utility to issue energy recovery bonds (“ERBs”) in connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s proceeding under Chapter 11 (“Chapter 11 Settlement Agreement”).  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.  PERF is expected to be dissolved in 2013.  (See Note 5 below.)  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 of PG&E Corporation, and the recovery property is not legally an asset of the Utility or PG&E Corporation.

At December 31, 2012, PG&E Corporation affiliates had entered into four tax equity agreements to fund residential and commercial retail solar energy installations with two privately held companies that are considered VIEs.  Under these agreements, PG&E Corporation has agreed to provide lease payments and investment contributions of up to $396 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies.  The majority of these amounts are recorded in other noncurrent assets – other in PG&E Corporation’s Consolidated Balance Sheets.  At December 31, 2012, PG&E Corporation had made total payments of $361 million under these agreements and received $228 million in benefits and customer payments.  In determining whether  PG&E Corporation is the primary beneficiary of any of these VIEs, PG&E Corporation assesses which of the variable interest holders has control over these companies’ significant economic activities, such as the design of the companies, vendor selection, construction, customer selection, and re-marketing activities after the termination of customer leases. PG&E Corporation determined that these companies control these activities, while its financial exposure from these agreements is generally limited to its lease payments and investment contributions to these companies.  Since PG&E Corporation was not the primary beneficiary of any of these VIEs at December 31, 2012, it did not consolidate any of them.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Current Regulatory Assets

At December 31, 2012 and 2011, the Utility had current regulatory assets of $564 million and $1,090 million, respectively.  At December 31, 2012, current regulatory assets consisted primarily of $230 million of the current portion of the price risk management regulatory asset, $62 million of the current portion of the Utility’s retained generation regulatory assets, and $54 million of the current portion of the electromechanical meters regulatory asset, each of which is expected to be recovered over the next year.  (See “Long-Term Regulatory Assets” below.)

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at December 31,
(in millions)	2012		2011
Pension benefits	$	3,275	$	2,899
Deferred income taxes		1,627		1,444
Utility retained generation		552		613
Environmental compliance costs		604		520
Price risk management		210		339
Electromechanical meters		194		247
Unamortized loss, net of gain, on reacquired debt		141		163
Other		206		281
Total long-term regulatory assets	$	6,809	$	6,506

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The regulatory asset for pension benefits represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP and also includes amounts that otherwise would be recorded to accumulated other comprehensive loss in the Consolidated Balance Sheets.  (See Note 12 below.)

The regulatory asset for deferred income taxes represents 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.  Based on current regulatory ratemaking and income tax laws, the Utility expects to recover the regulatory asset over the average plant depreciation lives of one to 45 years.

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 12 years.

The regulatory asset for environmental compliance costs represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP.  The Utility expects to recover these costs over the next 32 years, as the environmental compliance work is performed.  (See Note 15 below.)

The regulatory asset for price risk management represents the unrealized losses related to price risk management derivative instruments expected to be recovered as they are realized over the next 10 years as part of the Utility’s energy procurement costs.  (See Note 10 below.)

The regulatory asset for electromechanical meters represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices.  The Utility expects to recover the regulatory asset over the next four years.

The regulatory asset for unamortized loss, net of gain, on reacquired debt represents the expected future recovery of 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 14 years, which is the remaining amortization period of the reacquired debt.

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 regulatory assets for retained generation, regulatory assets for electromechanical meters, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Current Regulatory Liabilities

At December 31, 2012 and 2011, the Utility had current regulatory liabilities of $337 million and $161 million, respectively, consisting of amounts that it expects to refund to customers over the next 12 months. At December 31, 2012 current regulatory liabilities primarily included $158 million of ERB over collections, $84 million of proceeds from a greenhouse gas (“GHG”) emission auction to comply with California Air Resources Board requirements, and electricity supplier settlement agreements of $50 million (See Note 13 below).  Current regulatory liabilities are included within 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)	2012		2011
Cost of removal obligations	$	3,625	$	3,460
Recoveries in excess of AROs		620		611
Public purpose programs		590		499
Other		253		163
Total long-term regulatory liabilities	$	5,088	$	4,733

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The regulatory liability for cost of removal obligations represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.

The regulatory liability for recoveries in excess of AROs represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the Utility’s nuclear generation facilities.  Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust investments.  (See Note 11 below.)

The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances and other energy-using products, the California Solar Initiative program to promote the use of solar energy in homes and commercial, industrial, and agricultural properties, and the Self-Generation Incentive program to promote distributed generation technologies installed on the customer’s side of the utility meter.

Regulatory Balancing Accounts

The Utility’s current regulatory balancing accounts represent the amounts expected to be collected from or refunded to customers through authorized rate adjustments over the next 12 months.  Regulatory balancing accounts that the Utility does not expect to collect or refund over the next 12 months are included in other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets.

Current Regulatory Balancing Accounts, Net

	Receivable (Payable)
	Balance at December 31,
(in millions)	2012			2011
Distribution revenue adjustment mechanism	$	219		$	223
Utility generation		117			241
Hazardous substance		56			57
Public purpose programs		(83	)		97
Gas fixed cost		44			16
Energy recovery bonds		(43	)		(105	)
Energy procurement		77			(48	)
Department of Energy Settlement		(250	)		-
Other		165			227
Total regulatory balancing accounts, net	$	302		$	708

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 generation balancing account is used to record and recover the authorized revenue requirements associated with Utility-owned electric generation, including capital costs and related non-fuel operating and maintenance expenses.  The recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers fluctuates depending on the volume of electricity sales.  During the colder months of winter, there is generally an under-collection in these balancing accounts due to a lower volume of electricity sales and lower rates.  During the warmer months of summer, there is generally an over-collection due to a higher volume of electricity sales and higher rates.

The hazardous substance balancing accounts are used to record and recover hazardous substance remediation costs that are eligible for recovery through a CPUC-approved ratemaking mechanism.  (See Note 15 below.)

The public purpose programs balancing accounts are primarily used to record and recover the authorized revenue requirements associated with administering public purpose programs, as well as incentive awards earned by the Utility for achieving regulatory targets in the customer energy efficiency programs.  The public purpose programs primarily consist of energy efficiency programs, low-income energy efficiency programs, demand response programs, research, development, and demonstration programs, and renewable energy programs.

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The gas fixed-cost balancing account is used to record and recover authorized gas distribution revenue requirements and certain other authorized gas distribution-related costs.  Similar to the utility generation and the distribution revenue adjustment mechanism balancing accounts discussed above, the recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers fluctuates depending on the volume of gas sales.  During the colder months of winter, there is generally an over-collection in this balancing account primarily due to higher natural gas sales.  During the warmer months of summer, there is generally an under-collection primarily due to lower natural gas sales.

The ERBs balancing account is used to record and refund to customers the net refunds, claim offsets, and other credits received by the Utility from electricity suppliers related to Chapter 11 disputed claims and to record and recover authorized ERB servicing costs.  (See Note 13 below.)

The Utility is generally authorized to recover 100% of its prudently incurred electric energy procurement costs.  The Utility tracks energy procurement costs in balancing accounts and files annual forecasts of energy procurement costs that it expects to incur over the following year.  The Utility’s energy rates are set to recover such expected costs.

The Department of Energy balancing account is used to record and refund to customers the amounts received from the U.S. Department of Energy (“DOE”) during 2012 for a settlement agreement related to spent nuclear fuel storage costs incurred by the Utility.

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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)	2012			2011
PG&E Corporation
Senior notes, 5.75%, due 2014		350			350
Unamortized discount		-			(1	)
Total senior notes		350			349
Total PG&E Corporation long-term debt		350			349
Utility
Senior notes:
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			800
4.25% due 2021		300			300
3.25% due 2021		250			250
2.45% due 2022		400			-
6.05% due 2034		3,000			3,000
5.80% due 2037		950			950
6.35% due 2038		400			400
6.25% due 2039		550			550
5.40% due 2040		800			800
4.50% due 2041		250			250
4.45% due 2042		400			-
3.75% due 2042		350			-
Less: current portion		(400	)		-
Unamortized discount, net of premium		(51	)		(51	)
Total senior notes, net of current portion		10,899			10,149
Pollution control bonds:
Series 1996 C, E, F, 1997 B, variable rates (1), due 2026 (2)		614			614
Series 2004 A-D, 4.75%, due 2023 (3)		345			345
Series 2009 A-D, variable rates (4), due 2016 and 2026 (5)		309			309
Series 2010 E, 2.25%, due 2026 (6)		-			50
Less: current portion		-			(50	)
Total pollution control bonds		1,268			1,268
Total Utility long-term debt, net of current portion		12,167			11,417
Total consolidated long-term debt, net of current portion	$	12,517		$	11,766

At December 31, 2012, interest rates on these bonds and the related loans ranged from 0.10% to 0.14%.

(2) Each series of these bonds is supported by a separate letter of credit that expires on May 31, 2016. 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 consent from the issuer to the continuation of the series without a credit facility.

(3) The Utility has obtained credit support from an insurance company for these bonds.

(4) At December 31, 2012, interest rates on these bonds and the related loans ranged from 0.05% to 0.11%.

(5) Each series of these bonds is supported by a separate direct-pay letter of credit that expires on May 31, 2016.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.

(6) These bonds bore interest at 2.25% per year through April 1, 2012; and were subject to mandatory tender on April 2, 2012.  The Utility repurchased these bonds on April 2, 2012 and continues to hold them.

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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.  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 (“Code”), 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 debt principal repayment amounts at December 31, 2012 are reflected in the table below:

(in millions,
except interest rates)	2013			2014				2015			2016			2017			Thereafter				Total
PG&E Corporation
Average fixed interest rate		-				5.75	%			-		-			-				-				5.75	%
Fixed rate obligations	$	-			$	350			$	-	$	-		$	-			$	-			$	350
Utility
Average fixed interest rate		6.25	%			4.80	%			-		-			5.63	%			5.45	%			5.43	%
Fixed rate obligations	$	400			$	1,000			$	-	$	-		$	700			$	9,595			$	11,695
Variable interest rate
as of December 31, 2012		-				-				-		0.11	%		-				-				0.11	%
Variable rate obligations	$	-			$	-			$	-	$	923	(1)	$	-			$	-			$	923
Total consolidated debt	$	400			$	1,350			$	-	$	923		$	700			$	9,595			$	12,968

(1) These bonds, due in 2016 and 2026, are backed by letters of credit that expire on May 31, 2016.

Short-term Borrowings

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings on its revolving credit facilities and commercial paper program at December 31, 2012:

					Letters of
	Termination	Facility			Credit				Commercial			Facility
(in millions)	Date	Limit			Outstanding		Borrowings		Paper			Availability
PG&E Corporation	May 2016	$	300	(1)	$	-	$	120	$	-		$	180
Utility	May 2016		3,000	(2)		266		-		370	(3)		2,364	(3)
Total revolving credit facilities		$	3,300		$	266	$	120	$	370		$	2,544

(1) Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.

(2) Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.

(3) The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.

For 2012, the average outstanding borrowings on PG&E Corporation’s revolving credit facility was $21 million and the maximum outstanding balance during the year was $120 million.  For 2012, the Utility’s average outstanding commercial paper balance was $665 million and the maximum outstanding balance during the year was $1.4 billion.

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Revolving Credit Facilities

PG&E Corporation has a $300 million revolving credit facility with a syndicate of lenders.  The Utility has a $3.0 billion revolving credit facility with a syndicate of lenders.  The revolving credit facilities have terms of five years and all amounts are due and payable on the facilities’ termination date, May 31, 2016.  At PG&E Corporation’s and the Utility’s request and at the sole discretion of each lender, the facilities may be extended for additional periods.  The revolving credit facilities may be used for working capital and other corporate purposes.  The Utility’s revolving credit facility may also be used for the repayment of commercial paper.

Provided certain conditions are met, PG&E Corporation and the Utility have the right to increase, in one or more requests, given not more frequently than once a year, the aggregate lenders’ commitments under the revolving credit facilities by up to $100 million and $500 million, respectively, in the aggregate for all such increases.

Borrowings under the revolving credit facilities (other than swingline loans) bear interest based, at PG&E Corporation’s and the Utility’s election, on (1) a London Interbank Offered Rate (“LIBOR”) plus an applicable margin or (2) the base rate plus an applicable margin.  The base rate will equal the higher of the following: the administrative agent’s announced base rate, 0.5% above the federal funds rate, or the one-month LIBOR plus an applicable margin.  Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods.  PG&E Corporation and the Utility also will pay a facility fee on the total commitments of the lenders under the revolving credit facilities.  The applicable margins and the facility fees will be based on PG&E Corporation’s and the Utility’s senior unsecured debt ratings issued by Standard & Poor’s Rating Services and Moody’s Investor Service.  Facility fees are payable quarterly in arrears.

The revolving credit facilities include usual and customary covenants for revolving credit facilities of this type, including covenants limiting liens to those permitted under PG&E Corporation’s and the Utility’s senior note indentures, mergers, sales of all or substantially all of PG&E Corporation’s and the Utility’s assets, and other fundamental changes.  In addition, the revolving credit facilities require that PG&E Corporation and 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.  PG&E Corporation’s revolving credit facility agreement also requires that PG&E Corporation 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, 2012, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

Commercial Paper Program

The Utility has a $1.75 billion commercial paper program, the borrowings from which are used primarily to fund temporary financing needs.  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, 2012, the average yield on outstanding commercial paper was 0.36%.

Other Short-term Borrowings

In November 2011, the Utility issued $250 million principal amount of Floating Rate Senior Notes which were due and repaid in November 2012.  For the years ended December 31, 2012 and 2011, the average interest rate on the Floating Rate Senior Notes was 0.92% and 0.94%, respectively.

NOTE 5: ENERGY RECOVERY BONDS

In 2005, PERF issued two series of ERBs. The proceeds of the ERBs were used by PERF to purchase from the Utility the right known as “recovery property” to be paid a specific amount from a dedicated rate component.  The first series of ERBs included five classes aggregating to a $1.9 billion principal amount. The proceeds of the first series of ERBs were paid by PERF to the Utility and used by the Utility to refinance the remaining unamortized after-tax balance of the regulatory asset established under the Chapter 11 Settlement Agreement. The second series of ERBs included three classes aggregating to an $844 million principal amount. The proceeds of the second series of ERBs were paid by PERF to the Utility and used to pre-fund the Utility’s tax liability for bond-related charges collected from customers.

At December 31, 2011, the total amount of ERB principal outstanding was $423 million. The ERBs were paid in full when the final class matured on December 25, 2012.

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NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation

PG&E Corporation had 430,718,293 shares of common stock outstanding at December 31, 2012.  During 2012, PG&E Corporation issued 6,803,101 shares of its common stock under its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and its share-based compensation plans, generating $263 million of cash.

In November 2011, PG&E Corporation entered into an Equity Distribution Agreement providing for the sale of PG&E common stock having an aggregate gross sales 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.  During 2012, PG&E Corporation sold 5,446,760 shares of its common stock under the Equity Distribution Agreement for cash proceeds of $234 million, net of fees.  As of December 31, 2012, PG&E Corporation had the ability to issue an additional $64 million of its common stock under the November 2011 Equity Distribution Agreement.  In March 2012, PG&E Corporation sold 5,900,000 shares of its common stock in an underwritten public offering for cash proceeds of $254 million, net of fees and commissions.

Utility

As of December 31, 2012, PG&E Corporation held all of the Utility’s outstanding common stock.

Dividends

The Board of Directors of PG&E Corporation and the Utility declare dividends quarterly.  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.  In February, June, September, and December, 2012, the Board of Directors of PG&E Corporation declared a quarterly dividend of $0.455 per share.

PG&E Corporation and the Utility each have revolving credit facilities that require the respective company to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%.  Based on the calculation of this ratio for PG&E Corporation, no amount of PG&E Corporation’s reinvested earnings was restricted at December 31, 2012.  Based on the calculation of this ratio for the Utility, $1.1 billion of the Utility’s reinvested earnings was restricted at December 31, 2012.  In addition, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average.  At December 31, 2012, the Utility was required to maintain reinvested earnings of $6.3 billion as equity to meet this requirement.

In addition, to comply with the revolving credit facility’s 65% ratio requirement and the CPUC’s requirement to maintain a 52% equity component, $7.0 billion and $12.2 billion of the Utility’s net assets, respectively, were restricted at December 31, 2012 and could not be transferred to PG&E Corporation in the form of cash dividends.  As a holding company, PG&E Corporation depends on cash distributions from the Utility to meet its debt service and other financial obligations and to pay dividends on its common stock.

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Long-Term Incentive Plan

The PG&E Corporation 2006 Long-Term Incentive Plan (“2006 LTIP”) permits the award of various forms of incentive awards, including stock options, stock appreciation rights, restricted stock awards, restricted stock units (“RSUs”), performance shares, deferred compensation awards, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries.  Non-employee directors of PG&E Corporation are also eligible to receive share-based awards 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 4,548,119 shares were available for award at December 31, 2012.

The following table provides a summary of total compensation expense for PG&E Corporation for share-based incentive awards for 2012, 2011, and 2010:

(in millions)	2012		2011			2010
Restricted stock units	$	31	$	22		$	9
Other share-based compensation		-		1			14
Performance shares:
Equity awards		26		16			11
Liability awards		-		(13	)		22
Total compensation expense (pre-tax)	$	57	$	26		$	56
Total compensation expense (after-tax)	$	34	$	16		$	33

There were no significant share-based compensation costs capitalized during 2012, 2011, and 2010.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Restricted Stock Units

Each RSU represents one hypothetical share of PG&E Corporation common stock.  RSUs 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.  Vested RSUs are settled in shares 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.  RSU 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.

The weighted average grant-date fair value per RSUs granted during 2012, 2011, and 2010 was $42.17, $45.10, and $42.97, respectively.  The total fair value of RSUs that vested during 2012, 2011, and 2010 was $18 million, $11 million, and $5 million, respectively.  The tax benefit from RSUs that vested during 2012, 2011, and 2010 was not material.  As of December 31, 2012, $44 million of total unrecognized compensation costs related to nonvested RSUs was expected to be recognized over the remaining weighted average period of 2.19 years.

The following table summarizes RSU activity for 2012:

	Number of			Weighted Average Grant-
	Restricted Stock Units			Date Fair Value
Nonvested at January 1		1,626,048		$	42.57
Granted		923,001		$	42.17
Vested		(424,034	)	$	41.88
Forfeited		(55,724	)	$	42.64
Nonvested at December 31		2,069,291		$	42.52

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Performance Shares

In 2012, PG&E Corporation granted 834,420 contingent performance shares to eligible employees.  Performance shares vest after three years of service.  Performance shares granted in 2012, 2011, and 2010 are settled in shares of PG&E Corporation common stock and are classified as share-based equity awards.  Performance-based awards granted prior to 2010 are settled in cash and classified as a liability.  The amount of common stock (or cash with respect to grants before 2010) that recipients are entitled to receive, if any, will be determined based on PG&E Corporation’s annual total shareholder return relative to the performance of a specified group of peer companies for the applicable three-year performance period.  Total compensation expense for performance 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 performance shares, if any, will be paid in cash upon the vesting date based on the amount of common stock to which the recipients are entitled.

The weighted average grant-date fair value for performance shares granted during 2012, 2011, and 2010 was $41.93, $33.91, and $35.60 respectively.  There was no tax benefit associated with performance shares that vested during 2012, 2011, and 2010, as awards that settle in cash have no tax impact, and awards that settle in shares do not generate a tax benefit until vested.  The performance shares awarded in March 2010 will vest in March 2013.  As of December 31, 2012, $29 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted average period of 1.28 years.

The following table summarizes performance shares classified as equity awards activity for 2012:

	Number of			Weighted Average Grant-
	Performance Shares			Date Fair Value
Nonvested at January 1		1,325,406		$	34.64
Granted		834,420		$	41.93
Vested		(425	)	$	34.86
Forfeited (1)		(661,928	)	$	35.71
Nonvested at December 31		1,497,473		$	38.15
(1) Includes performance shares that expired with zero value as performance targets were not met.

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.  PG&E Corporation does not have any preferred stock outstanding.

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.

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The following table summarizes the Utility’s outstanding preferred stock, none of which had mandatory redemption provisions at December 31, 2012 and 2011:

(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

At December 31, 2012, annual dividends on the Utility’s nonredeemable preferred stock ranged 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, 2012, 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 2012, 2011, and 2010 the Utility paid $14 million of dividends on preferred stock.

NOTE 8: EARNINGS PER SHARE

PG&E Corporation’s basic earnings per common share (“EPS”) is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.  The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2012 and 2011.

	Year Ended December 31,
(in millions, except per share amounts)	2012		2011
Income available for common shareholders	$	816	$	844
Weighted average common shares outstanding, basic		424		401
Add incremental shares from assumed conversions:
Employee share-based compensation		1		1
Weighted average common share outstanding, diluted		425		402
Total earnings per common share, diluted	$	1.92	$	2.10

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For 2010, PG&E Corporation calculated EPS using the “two-class” method because PG&E Corporation’s convertible subordinated notes that were outstanding prior to June 29, 2010 were considered to be participating securities.  In applying the two-class method, undistributed earnings were allocated to both common shares and participating securities. In calculating diluted EPS for 2010, PG&E Corporation applied the “if-converted” method to reflect the dilutive effect of the convertible subordinated notes to the extent that the impact was dilutive when compared to basic EPS.  The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating basic and diluted EPS for 2010:

	Year Ended December 31, 2010
(in millions, except per share amounts)	Basic		Diluted
Income available for common shareholders	$	1,099	$	1,099
Less: distributed earnings to common shareholders		706		-
Undistributed earnings	$	393	$	1,099
Allocation of earnings to common shareholders
Distributed earnings to common shareholders	$	706	$	-
Undistributed earnings allocated to common shareholders		385		1,099
Add: Interest expense on convertible subordinated notes, net of tax		-		8
Total common shareholders earnings and assumed conversion	$	1,091	$	1,107
Weighted average common shares outstanding		382		382
Add incremental shares from assumed conversions:
Convertible subordinated notes		8		8
Employee share-based compensation		-		2
Weighted average common shares outstanding and participating securities		390		392
Net earnings per common share, basic
Distributed earnings, basic (1)	$	1.85	$	-
Undistributed earnings		1.01		2.82
Total	$	2.86	$	2.82

(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.

For each of the periods presented above, the calculation of outstanding common 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) by taxing jurisdiction were as follows:

	PG&E Corporation									Utility
	Year Ended December 31,
(in millions)	2012			2011			2010			2012			2011			2010
Current:
Federal	$	(74	)	$	(77	)	$	(12	)	$	(52	)	$	(83	)	$	(54	)
State		33			152			130			41			161			134
Deferred:
Federal		374			504			525			404			534			589
State		(92	)		(135	)		(91	)		(91	)		(128	)		(90	)
Tax credits		(4	)		(4	)		(5	)		(4	)		(4	)		(5	)
Income tax provision	$	237		$	440		$	547		$	298		$	480		$	574

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The following table describes net deferred income tax liabilities:

	PG&E Corporation					Utility
	Year Ended December 31,
(in millions)	2012			2011		2012			2011
Deferred income tax assets:
Customer advances for construction	$	101		$	108	$	101		$	108
Reserve for damages		175			243		175			243
Environmental reserve		97			157		97			157
Compensation		229			310		179			258
Net operating loss carry forward		938			728		736			567
Other		264			217		255			180
Total deferred income tax assets	$	1,804		$	1,763	$	1,543		$	1,513
Deferred income tax liabilities:
Regulatory balancing accounts	$	256		$	643	$	256		$	643
Property related basis differences		7,449			6,544		7,447			6,536
Income tax regulatory asset		663			588		663			588
Other		173			192		99			105
Total deferred income tax liabilities	$	8,541		$	7,967	$	8,465		$	7,872
Total net deferred income tax liabilities	$	6,737		$	6,204	$	6,922		$	6,359
Classification of net deferred income tax liabilities:
Included in current liabilities (assets)	$	(11	)	$	196	$	(17	)	$	199
Included in noncurrent liabilities		6,748			6,008		6,939			6,160
Total net deferred income tax liabilities	$	6,737		$	6,204	$	6,922		$	6,359

The following table reconciles income tax expense at the federal statutory rate to the income tax provision:

	PG&E Corporation									Utility
	Year Ended December 31,
	2012			2011			2010			2012			2011			2010
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)		(3.9	)		1.1			0.7			(3.0	)		1.6			1.0
Effect of regulatory treatment
of fixed asset differences		(4.1	)		(4.4	)		(3.1	)		(3.9	)		(4.2	)		(3.0	)
Tax credits		(0.6	)		(0.5	)		(0.4	)		(0.6	)		(0.5	)		(0.4	)
Benefit of loss carryback		(0.7	)		(1.9	)		-			(0.4	)		(2.1	)		-
Non deductible penalties		0.6			6.5			0.2			0.5			6.3			0.2
Other, net		(3.8	)		(1.5	)		0.8			(0.8	)		0.1			1.1
Effective tax rate		22.5	%		34.3	%		33.2	%		26.8	%		36.2	%		33.9	%

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Unrecognized tax benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation									Utility
	2012			2011			2010			2012			2011			2010
(in millions)
Balance at beginning of year	$	506		$	714		$	673		$	503		$	712		$	652
Additions for tax position taken
during a prior year		32			2			27			26			2			27
Reductions for tax position
taken during a prior year		(13	)		(198	)		(20	)		(10	)		(196	)		-
Additions for tax position
taken during the current year		67			3			89			67			-			87
Settlements		(11	)		(15	)		(55	)		(11	)		(15	)		(54	)
Balance at end of year	$	581		$	506		$	714		$	575		$	503		$	712

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2012 for PG&E Corporation and the Utility was $18 million, with the remaining balance representing the potential deferral of taxes to later years.

PG&E Corporation and the Utility recognize accrued interest related to unrecognized tax benefits as income tax expense in the Consolidated Statements of Income.  Interest income and interest expense for the years ended December 31, 2012, December 31, 2011, and December 31, 2010 were immaterial.

As of December 31, 2012 and December 31, 2011, PG&E Corporation and the Utility had receivables for accrued interest income.  The amounts of these receivables were immaterial.

The Internal Revenue Service (“IRS”) is working with the utility industry to finalize guidance on what is a repair deduction for tax purposes for the natural gas transmission, natural gas distribution, and electric generation businesses.  PG&E Corporation and the Utility expect the IRS to release this guidance in the first half of 2013.  PG&E Corporation and the Utility expect the unrecognized tax benefits may change significantly within the next 12 months.

The IRS is auditing a 2008 accounting method change of the Utility to accelerate the amount of deductible repairs.  The audit is expected to be completed in 2013.  The resolution of the audit could result in a significant change in unrecognized tax benefit.  However, PG&E Corporation and the Utility cannot estimate the change of unrecognized tax benefits related to the items discussed above.

Tax settlements and years that remain subject to examination

In 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 its acceptance of the return.  The IRS partially accepted the 2008 return, withholding two matters for further review.  In December 2010, the IRS accepted the 2009 tax return without change.  In September 2011, the IRS partially accepted the 2010 return, withholding two matters for further review.  In September 2012, the IRS partially accepted the 2011 return, withholding several matters for future review.

The most significant of the matters withheld for further review in each of these years relates to a tax accounting method change of the Utility related to repairs.  The IRS has not completed its review of these claims.

Loss carry forwards

As of December 31, 2012, PG&E Corporation had approximately $2.1 billion of federal net operating loss carry forwards and $12 million of tax credit carry forwards, which will expire between 2029 and 2032.  In addition, PG&E Corporation had approximately $128 million of loss carry forwards related to charitable contributions, which will expire between 2013 and 2017.  PG&E Corporation believes it is more likely than not the tax benefits associated with the federal operating loss, charitable contributions, and tax credits can be realized within the carry forward periods, therefore no valuation allowance was recognized as of December 31, 2012.  As of December 31, 2012, PG&E Corporation had approximately $19 million of federal net operating loss carry forwards related to the tax benefit on employee stock plans that would be recorded in additional paid-in capital when used.

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NOTE 10: DERIVATIVES

Use of Derivative Instruments

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 and futures contracts that require payments to or from counterparties based upon the difference between two prices for a predetermined contractual quantity; and

·   option contracts that provide the Utility with the right to buy a commodity at a predetermined price and option contracts that require payments from counterparties if market prices exceed a predetermined price.

These instruments are not held for speculative purposes and are subject to certain regulatory requirements.  Customer rates are designed to recover the Utility’s reasonable costs of providing services, including the costs related to price risk management activities.

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets.  As long as the current ratemaking mechanism discussed above remains in place and the Utility’s price risk management activities are carried out in accordance with CPUC directives, the Utility expects to recover fully, in rates, all costs related to derivatives.  Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives 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 commodity derivatives 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 or refund to customers.

The Utility elects the normal purchase and sale exception for eligible derivatives.  Derivatives that require 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 derivatives that are eligible for the normal purchase and sales exception are not reflected in the Consolidated Balance Sheets.

Electricity Procurement

The Utility enters into third-party power purchase agreements for 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 derivatives.  The Utility elects the normal purchase and sale exception for eligible derivatives.

A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms.  In order to reduce volatility in customer rates, the Utility may enter into financial swap and/or financial option contracts to effectively fix and/or cap  the price of future purchases and reduce cash flow variability associated with fluctuating electricity prices.  These financial contracts are considered derivatives.

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Electric Transmission Congestion Revenue Rights

The California electric transmission grid, controlled by the California Independent System Operator (“CAISO”), is subject to transmission constraints when there is insufficient transmission capacity to supply the market.  The CAISO imposes congestion charges on market participants to manage transmission congestion.  The revenue generated from congestion charges is allocated to holders of congestion revenue rights (“CRRs”).  CRRs allow market participants to hedge the financial risk of CAISO-imposed congestion charges in the 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, such as the Utility, 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 Utility participates in the allocation and auction phases of the annual and monthly CRR processes.  CRRs are considered derivatives.

Natural Gas Procurement (Electric Fuels Portfolio)

The Utility’s electric procurement portfolio is exposed to natural gas price risk primarily through physical natural gas commodity purchases to fuel natural gas generating facilities, and electricity procurement contracts indexed to natural gas prices.  To reduce the volatility in customer rates, the Utility may enter into financial swap contracts or financial option contracts, or both.  The Utility also enters into fixed-price forward contracts for natural gas to reduce future cash flow variability from fluctuating natural gas prices.  These instruments are considered derivatives.

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 natural 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 natural gas prices during peak winter months.  These financial instruments are considered derivatives.

Volume of Derivative Activity

At December 31, 2012, the volumes of PG&E Corporation’s and the Utility’s outstanding derivatives were as follows:

		Contract Volume (1)
				1 Year or		3 Years or
				Greater but		Greater but
		Less Than 1		Less Than 3		Less Than 5		5 Years or
Underlying Product	Instruments	Year		Years		Years		Greater (2)
Natural Gas (3)	Forwards and
(MMBtus (4))	Swaps		329,466,510		98,628,398		5,490,000		-
	Options		221,587,431		216,279,767		10,050,000		-
Electricity	Forwards and
(Megawatt-hours)	Swaps		2,537,023		3,541,046		2,009,505		2,538,718
	Options		-		239,015		239,233		119,508
	Congestion
	Revenue Rights		74,198,690		74,187,803		74,240,147		25,699,804

(1)Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each period.

(2) Derivatives in this category expire between 2018 and 2023.

(3) Amounts shown are for the combined positions of the electric fuels and core gas portfolios.

(4) Million British Thermal Units.

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At December 31, 2011, the volumes of PG&E Corporation’s and the Utility’s outstanding derivatives were as follows:

		Contract Volume (1)
				1 Year or		3 Years or
				Greater but		Greater but
		Less Than 1		Less Than 3		Less Than 5		5 Years or
Underlying Product	Instruments	Year		Years		Years		Greater (2)
Natural Gas (3)	Forwards and
(MMBtus (4))	Swaps		500,375,394		212,088,902		6,080,000		-
	Options		257,766,990		336,543,013		-		-
Electricity	Forwards and
(Megawatt-hours)	Swaps		4,718,568		5,206,512		2,142,024		3,754,872
	Options		1,248,000		132,048		264,348		264,096
	Congestion
	Revenue Rights		84,247,502		72,882,246		72,949,250		61,673,535

(1)Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each period.

(2) Derivatives in this category expire between 2017 and 2022.

(3) Amounts shown are for the combined positions of the electric fuels and core gas portfolios.

(4) Million British Thermal Units.

Presentation of Derivative Instruments in the Financial Statements

In PG&E Corporation’s and the Utility’s Consolidated Balance Sheets, derivatives are presented on a net basis by counterparty where the right and the intention to offset exists under a master netting agreement.  The net balances include outstanding cash collateral associated with derivative positions.

At December 31, 2012, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
	Gross Derivative											Total Derivative
(in millions)	Balance				Netting				Cash Collateral			Balance
Current assets – other		$	48			$	(25	)		$	36		$	59
Other noncurrent assets – other			99				(11	)			-			88
Current liabilities – other			(255	)			25				115			(115	)
Noncurrent liabilities – other			(221	)			11				14			(196	)
Total commodity risk		$	(329	)		$	-			$	165		$	(164	)

At December 31, 2011, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
	Gross Derivative											Total Derivative
(in millions)	Balance				Netting				Cash Collateral			Balance
Current assets – other		$	54			$	(39	)		$	103		$	118
Other noncurrent assets – other			113				(59	)			-			54
Current liabilities – other			(489	)			39				274			(176	)
Noncurrent liabilities – other			(398	)			59				101			(238	)
Total commodity risk		$	(720	)		$	-			$	478		$	(242	)

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Gains and losses recorded on PG&E Corporation’s and the Utility’s derivatives were as follows:

	Commodity Risk
	For the year ended December 31,
(in millions)	2012				2011				2010
Unrealized gain/(loss) - regulatory assets and liabilities (1)		$	391			$	21			$	(260	)
Realized loss - cost of electricity (2)			(486	)			(558	)			(573	)
Realized loss - cost of natural gas (2)			(38	)			(106	)			(79	)
Total commodity risk		$	(133	)		$	(643	)		$	(912	)

(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 derivatives 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 derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies.  At December 31, 2012, the Utility’s credit rating was investment grade.  If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions.

The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows:

	Balance at December 31,
(in millions)	2012			2011
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(266	)	$	(611	)
Related derivatives in an asset position		59			86
Collateral posting in the normal course of business related to
these derivatives		103			250
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(104	)	$	(275	)

(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 – 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 (assets held in rabbi trusts are held by PG&E Corporation and not the Utility):

	Fair Value Measurements
	At December 31, 2012
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Money market investments	$	209	$	-	$	-	$	-		$	209
Nuclear decommissioning trusts
Money market investments		21		-		-		-			21
U.S. equity securities		940		9		-		-			949
Non-U.S. equity securities		379		-		-		-			379
U.S. government and agency securities		681		139		-		-			820
Municipal securities		-		59		-		-			59
Other fixed-income securities		-		173		-		-			173
Total nuclear decommissioning trusts (2)		2,021		380		-		-			2,401
Price risk management instruments
(Note 10)
Electricity		1		60		80		6			147
Gas		-		5		1		(6	)		-
Total price risk management instruments		1		65		81		-			147
Rabbi trusts
Fixed-income securities		-		30		-		-			30
Life insurance contracts		-		72		-		-			72
Total rabbi trusts		-		102		-		-			102
Long-term disability trust
Money market investments		10		-		-		-			10
U.S. equity securities		-		14		-		-			14
Non-U.S. equity securities		-		11		-		-			11
Fixed-income securities		-		136		-		-			136
Total long-term disability trust		10		161		-		-			171
Total assets	$	2,241	$	708	$	81	$	-		$	3,030
Liabilities:
Price risk management instruments
(Note 10)
Electricity	$	155	$	144	$	160	$	(156	)	$	303
Gas		8		9		-		(9	)		8
Total liabilities	$	163	$	153	$	160	$	(165		$	311

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Excludes $240 million at December 31, 2012 primarily related to deferred taxes on appreciation of investment value.

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	Fair Value Measurements
	At December 31, 2011
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Money market investments	$	206	$	-	$	-	$	-		$	206
Nuclear decommissioning trusts
Money market investments		24		-		-		-			24
U.S. equity securities		841		8		-		-			849
Non-U.S. equity securities		323		-		-		-			323
U.S. government and agency securities		720		156		-		-			876
Municipal securities		-		58		-		-			58
Other fixed-income securities		-		99		-		-			99
Total nuclear decommissioning trusts (2)		1,908		321		-		-			2,229
Price risk management instruments
(Note 10)
Electricity		-		92		69		8			169
Gas		-		6		-		(3	)		3
Total price risk management instruments		-		98		69		5			172
Rabbi trusts
Fixed-income securities		-		25		-		-			25
Life insurance contracts		-		67		-		-			67
Total rabbi trusts		-		92		-		-			92
Long-term disability trust
Money market investments		13		-		-		-			13
U.S. equity securities		-		15		-		-			15
Non-U.S. equity securities		-		9		-		-			9
Fixed-income securities		-		145		-		-			145
Total long-term disability trust		13		169		-		-			182
Total assets	$	2,127	$	680	$	69	$	5		$	2,881
Liabilities:
Price risk management instruments
(Note 10)
Electricity	$	411	$	289	$	143	$	(441	)	$	402
Gas		31		13		-		(32	)		12
Total liabilities	$	442	$	302	$	143	$	(473	)	$	414

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Excludes $188 million at December 31, 2011 primarily related to deferred taxes on appreciation of investment value.

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Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above:

Money Market Investments

PG&E Corporation and the Utility invest 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 U.S. Treasury bills, U.S. agency securities, certificates of deposit, and commercial paper with a maximum weighted average maturity of 60 days or less.  PG&E Corporation’s and the Utility’s investments in these money market funds are valued using unadjusted prices for identical assets in an active market and are thus classified as Level 1.  Money market funds are recorded as cash and cash equivalents in PG&E Corporation’s and the Utility’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 composed primarily of equity securities, debt securities, and life insurance policies.  In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

Equity securities primarily include investments in common stock, which are valued based on unadjusted prices for identical securities in active markets and are classified as Level 1.  Equity securities also include commingled funds composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world, which are classified as Level 2.  Price quotes for the assets held by these funds are readily observable and available.

Debt securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of debt securities classified as Level 2.  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 ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.  (See Note 10 above.)

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model.  Exchange-traded forwards and swaps that are valued using observable market forward prices for the underlying commodity are classified as Level 1.  Over-the-counter forwards and swaps that are identical to exchange-traded forwards and swaps or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2.  Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3.  These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.

Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.  Over-the-counter options are classified as Level 3 and are valued using a standard option pricing model, which includes forward prices for the underlying commodity, time value at a risk-free rate, and volatility.  For periods where market data is not available, the Utility extrapolates observable data using internal models.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  CRRs are valued based on prices observed in the CAISO auction, which are discounted at the risk-free rate.  Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions.  CRRs are classified as Level 3.

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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. For the year ended December 31, 2012, there were no significant transfer between levels.

At December 31, 2011, the valuation of price risk management over-the-counter forwards and swaps and exchange-traded options incorporated market observable and market corroborated inputs, where certain previously-considered unobservable inputs became observable.  Therefore, the Utility transferred these instruments out of Level 3 and into Level 2.  There were no significant transfers between Levels 1 and 2 in the year ended December 31, 2011.

Level 3 Measurements and Sensitivity Analysis

The Utility’s Market and Credit Risk Management department is responsible for determining the fair value of the Utility’s price risk management derivatives.  Market and Credit Risk Management reports to the Chief Risk Officer of the Utility.  Market and Credit Risk Management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments.  These models use pricing inputs from brokers and historical data.  The Market and Credit Risk Management department and the Controller’s organization collaborate to determine the appropriate fair value methodologies and classification for each derivative.  Inputs used and fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.  Valuation models and techniques are reviewed periodically.

CRRs and power purchase agreements are valued using historical prices or significant unobservable inputs derived from internally developed models.  Historical prices include CRR auction prices.  Unobservable inputs include forward electricity prices.  Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively.  All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments.  (See Note 10 above.)

	Fair Value at
(in millions)	December 31, 2012
Fair Value Measurement	Assets			Liabilities			Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights		$	80		$	16	Market approach	CRR auction prices		$	(9.04) - 55.15
Power purchase agreements		$	-		$	145	Discounted cash flow	Forward prices		$	8.59 - 62.90

(1)   (1) Represents price per megawatt-hour

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2012 and 2011, respectively:

	Price Risk Management Instruments
(in millions)	2012			2011
Liability balance as of January 1	$	(74	)	$	(399	)
Realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)		(5	)		122
Transfers out of Level 3		-			203
Liability balance as of December 31	$	(79	)	$	(74	)

(1) Price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and   purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.

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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, 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, 2012 and 2011, as they are short-term in nature or have interest rates that reset daily.

·   The fair values of the Utility’s fixed-rate senior notes and fixed-rate pollution control bond loan agreements and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at December 31, 2012 and 2011.  The fair value of the ERBs issued by PERF was also based on quoted market prices at December 31, 2011.

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,
	2012						2011
(in millions)	Carrying Amount			Level 2 Fair Value			Carrying Amount			Level 2 Fair Value
Debt (Note 4)
PG&E Corporation		$	349		$	371		$	349		$	380
Utility			11,645			13,946			10,545			12,543
Energy recovery bonds (Note 5)			-			-			423			433

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Nuclear Decommissioning Trust Investments

The following table provides a summary of available-for-sale investments held in the Utility’s nuclear decommissioning trusts:

			Total		Total
	Amortized		Unrealized		Unrealized			Total Fair
(in millions)	Cost		Gains		Losses			Value (1)
As of December, 2012
Money market investments	$	21	$	-	$	-		$	21
Equity securities
U.S.		331		618		-			949
Non-U.S.		199		181		(1	)		379
Debt securities
U.S. government and agency securities		723		97		-			820
Municipal securities		56		4		(1	)		59
Other fixed-income securities		168		5		-			173
Total	$	1,498	$	905	$	(2	)	$	2,401
As of December 31, 2011
Money market investments	$	24	$	-	$	-		$	24
Equity securities
U.S.		334		518		(3	)		849
Non-U.S.		194		131		(2	)		323
Debt securities
U.S. government and agency securities		774		102		-			876
Municipal securities		56		2		-			58
Other fixed-income securities		96		3		-			99
Total	$	1,478	$	756	$	(5	)	$	2,229

(1) Excludes $240 million and $188 million at December 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of debt securities by contractual maturity is as follows:

(in millions)	As of December 31, 2012
Less than 1 year	$	5
1–5 years		456
5–10 years		218
More than 10 years		373
Total maturities of debt securities	$	1,052

The following table provides a summary of activity for the debt and equity securities:

	2012			2011			2010
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust
investments	$	1,133		$	1,928		$	1,405
Gross realized gains on sales of securities held as available-for-sale		19			43			42
Gross realized losses on sales of securities held as available-for-sale		(17	)		(30	)		(11	)

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NOTE 12: EMPLOYEE BENEFIT PLANS

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees, as well as contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.  The trusts underlying certain of these plans are qualified trusts under the Internal Revenue Code of 1986, as amended (“Code”).  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.

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’s minimum funding requirements related to its pension plans was zero.

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 2012 and 2011:

Pension Benefits

(in millions)	2012			2011
Change in plan assets:
Fair value of plan assets at January 1	$	10,993		$	10,250
Actual return on plan assets		1,488			1,016
Company contributions		282			230
Benefits and expenses paid		(622	)		(503	)
Fair value of plan assets at December 31	$	12,141		$	10,993
Change in benefit obligation:
Projected benefit obligation at January 1	$	14,000		$	12,071
Service cost for benefits earned		396			320
Interest cost		658			660
Actuarial loss		1,099			1,450
Plan amendments		9			-
Transitional costs		1			2
Benefits and expenses paid		(622	)		(503	)
Projected benefit obligation at December 31 (1)	$	15,541		$	14,000
Funded status:
Current liability	$	(6	)	$	(5	)
Noncurrent liability		(3,394	)		(3,002	)
Accrued benefit cost at December 31	$	(3,400	)	$	(3,007	)

(1) PG&E Corporation’s accumulated benefit obligation was $13,778 million and $12,285 million at December 31, 2012 and 2011, respectively.

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Other Benefits

(in millions)	2012			2011
Change in plan assets:
Fair value of plan assets at January 1	$	1,491		$	1,337
Actual return on plan assets		191			95
Company contributions		149			137
Plan participant contribution		55			52
Benefits and expenses paid		(128	)		(130	)
Fair value of plan assets at December 31	$	1,758		$	1,491
Change in benefit obligation:
Benefit obligation at January 1	$	1,885		$	1,755
Service cost for benefits earned		49			42
Interest cost		83			91
Actuarial loss		(23	)		63
Plan amendments		5			-
Benefits paid		(119	)		(130	)
Federal subsidy on benefits paid		5			12
Plan participant contributions		55			52
Benefit obligation at December 31	$	1,940		$	1,885
Funded status:
Noncurrent liability	$	(181	)	$	(394	)
Accrued benefit cost at December 31	$	(181	)	$	(394	)

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

During 2012, the Utility’s defined benefit pension plan was amended to include a new cash balance benefit formula.  Eligible employees hired after December 31, 2012 will participate in the cash balance benefit.  Eligible employees hired before January 1, 2013 will have a one-time opportunity to elect to participate in the cash balance benefit going forward, beginning on January 1, 2014 or to continue participating in the existing defined benefit plan.  As long as pension benefit costs continue to be recoverable through customer rates, PG&E Corporation and the Utility anticipate that this amendment will have no impact on net income.

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Components of Net Periodic Benefit Cost

Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income for 2012, 2011, and 2010 was as follows:

Pension Benefits

(in millions)	2012			2011			2010
Service cost for benefits earned	$	396		$	320		$	279
Interest cost		658			660			645
Expected return on plan assets		(598	)		(669	)		(624	)
Amortization of prior service cost		20			34			53
Amortization of unrecognized loss		123			50			44
Net periodic benefit cost		599			395			397
Less: transfer to regulatory account (1)		(301	)		(139	)		(233	)
Total	$	298		$	256		$	164

 (1) The Utility recorded $301 million, $139 million, and $233 million for the years ended December 31, 2012, 2011, and 2010, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates

Other Benefits

(in millions)	2012			2011			2010
Service cost for benefits earned	$	49		$	42		$	36
Interest cost		83			91			88
Expected return on plan assets		(77	)		(82	)		(74	)
Amortization of transition obligation		24			26			26
Amortization of prior service cost		25			27			25
Amortization of unrecognized loss (gain)		6			4			3
Net periodic benefit cost	$	110		$	108		$	104

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Components of Accumulated Other Comprehensive Income

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, 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.

Regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between pension expense or income calculated in accordance with GAAP 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.

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The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2013 are as follows:

Pension Benefit

(in millions)
Unrecognized prior service cost	$	20
Unrecognized net loss		110
Total	$	130

Other Benefits

(in millions)
Unrecognized prior service cost	$	24
Unrecognized net loss		6
Total	$	30

There were no material differences between the estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation and the Utility.

Valuation Assumptions

The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic benefit costs.  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,
	2012			2011			2010			2012			2011			2010
Discount rate		3.98	%		4.66	%		5.42	%		3.75 - 4.08	%		4.41 - 4.77	%		5.11 - 5.56	%
Average rate of future
compensation increases		4.00	%		5.00	%		5.00	%		-			-			-
Expected return on plan assets		5.40	%		5.50	%		6.60	%		2.90 - 6.10	%		4.40 - 5.50	%		5.20 - 6.60	%

The assumed health care cost trend rate as of December 31, 2012 was 7.5%, 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:

	One-			One-
	Percentage-			Percentage-
	Point			Point
(in millions)	Increase			Decrease
Effect on postretirement benefit obligation		$	108		$	(111	)
Effect on service and interest cost			8			(8	)

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 5.4% compares to a ten-year actual return of 10.2%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 648 Aa-grade non-callable bonds at December 31, 2012.  This yield curve has discount rates that vary based on the duration of the obligations.  The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

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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 in 2011 exceeded expectations due to a higher than expected return on fixed-income debt investments.   The actual return on plan assets in 2012 was in line with 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, credit, 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, 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 portfolios that include common stock and commingled funds across multiple industry sectors.  Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets.  Real assets include commodities futures, global real estate investment trusts (“REITS”), global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios.

Over the last three years, target allocations for equity investments have generally declined in favor of longer-maturity fixed-income investments and real assets as a means of dampening future funded status volatility.  In 2012, equity index futures were added to maintain existing equity exposure while adding exposure to fixed-income securities.  Historically, the equity investment allocation was implemented through diversified U.S. equity, non-U.S. equity, and global portfolios.  In 2012, the U.S. equity and non-U.S. equity allocations were eliminated and became a combined global equity allocation.

In accordance with the pension plan’s investment guidelines, derivative instruments such as equity-index futures contracts are used primarily to maintain equity and fixed income portfolio exposure consistent with the investment policy and to rebalance the fixed income/equity allocation of the pension’s portfolio.  Foreign currency exchange contracts are also used to hedge a portion of the currency of the global equity investments.

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 designed 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 are as follows:

	Pension Benefits									Other Benefits
	2013			2012			2011			2013			2012			2011
Global equity securities		25	%		35	%		5	%		28	%		38	%		3	%
U.S. equity securities		-	%		-	%		26	%		-	%		-	%		28	%
Non-U.S. equity securities		-	%		-	%		14	%		-	%		-	%		15	%
Absolute return		5	%		5	%		5	%		4	%		4	%		4	%
Real assets		10	%		10	%		-	%		8	%		8	%		-	%
Extended fixed-income securities		3	%		3	%		-	%		-	%		-	%		-	%
Fixed-income securities		57	%		47	%		50	%		60	%		50	%		50	%
Total		100	%		100	%		100	%		100	%		100	%		100	%

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Fair Value Measurements

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2012 and 2011.

	Fair Value Measurements
	At December 31,
	2012								2011
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Benefits:
Money market investments	$	112	$	-	$	-	$	112	$	51	$	-	$	-	$	51
U.S. equity securities		-		-		-		-		273		2,161		-		2,434
Non-U.S. equity securities		-		-		-		-		131		1,363		-		1,494
Global equity securities		402		3,017		-		3,419		-		197		-		197
Absolute return		-		-		513		513		-		-		487		487
Real assets		525		-		285		810		522		-		65		587
Fixed-income securities:
U.S. government		1,576		139		-		1,715		1,224		172		-		1,396
Corporate		3		4,275		611		4,889		2		3,083		585		3,670
Other		-		576		-		576		1		688		-		689
Total	$	2,618	$	8,007	$	1,409	$	12,034	$	2,204	$	7,664	$	1,137	$	11,005
Other Benefits:
Money market investments	$	77	$	-	$	-	$	77	$	48	$	-	$	-	$	48
U.S. equity securities		-		-		-		-		86		222		-		308
Non-U.S. equity securities		-		-		-		-		79		108		-		187
Global equity securities		118		397		-		515		-		19		-		19
Absolute return		-		-		49		49		-		-		47		47
Real assets		68		-		28		96		31		-		6		37
Fixed-income securities:
U.S. government		148		5		-		153		151		-		-		151
Corporate		9		795		1		805		-		681		1		682
Other		-		38		-		38		1		44		-		45
Total	$	420	$	1,235	$	78	$	1,733	$	396	$	1,074	$	54	$	1,524
Total plan assets at fair value							$	13,767							$	12,529

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $132 million and other net liabilities of $45 million at December 31, 2012 and 2011, respectively.  These net assets and net liabilities were comprised primarily of cash, accounts receivable, accounts payable, and deferred taxes.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above.  All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days.

Money Market Investments

Money market investments consist primarily of commingled funds of U.S. government 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.

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Equity Securities

The global equity categories include equity investments in common stock and equity-index futures, and commingled funds comprised of equity across multiple industries and regions of the world.  Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets.  These equity investments are generally valued based on unadjusted prices in active markets for identical securities.  Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets.  Collateral posted related to these futures consist of money market investments that are considered Level 1 assets.  Commingled funds are valued using a net asset value per share and 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 using a net asset value per share 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.

Real Assets

The real asset category includes portfolios of commodities, commodities futures, global REITS, global listed infrastructure equities, and private real estate funds.  The commodities, commodities futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets.  Collateral posted related to the commodities futures consist of money market investments that are considered Level 1 assets.  Private real estate funds are valued using a net asset value per share derived using appraisals, pricing models, and valuation inputs that are unobservable and 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 derivative instruments.  These securities are classified as Level 2 assets.  Corporate fixed-income also includes commingled funds that are valued using a net asset value per share and are comprised of corporate debt instruments.  Commingled funds are considered Level 2 assets.  Corporate fixed income also includes insurance contracts for deferred annuities.  These investments are valued using a net asset value per share using pricing models and valuation inputs that are unobservable and are considered Level 3 assets.

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 and are considered Level 2 assets.  Other fixed-income also includes municipal bonds and index futures.  Collateral posted related to the index futures consist of money market investments that are considered Level 1 assets.  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.

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.  As shown in the table below, transfers out of Level 3 represent assets that were previously classified as Level 3 for which the lowest significant input became observable during the period.  No significant transfers between Levels 1 and 2 occurred in the years ended December 31, 2012 and 2011.

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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, 2012 and 2011:

	Pension Benefits
	Absolute			Corporate			Other
(in millions)	Return			Fixed-Income			Fixed-Income			Real Assets		Total
Balance as of January 1, 2011	$	494		$	549		$	120		$	-	$	1,163
Actual return on plan assets:
Relating to assets still held at the reporting date		5			57			(2	)		-		60
Relating to assets sold during the period		2			-			1			-		3
Purchases, issuances, sales, and settlements
Purchases		-			14			2			65		81
Settlements		(14	)		(35	)		(58	)		-		(107	)
Transfers out of Level 3		-			-			(63	)		-		(63	)
Balance as of December 31, 2011	$	487		$	585		$	-		$	65	$	1,137
Actual return on plan  assets:
Relating to assets still held at the reporting date		26			28			-			12		66
Relating to assets sold during the period		-			(1	)		-			-		(1	)
Purchases, issuances, sales, and settlements
Purchases		-			12			-			208		220
Settlements		-			(13	)		-			-		(13	)
Balance as of December 31, 2012	$	513		$	611		$	-		$	285	$	1,409

	Other Benefits
	Absolute			Corporate			Other
(in millions)	Return			Fixed-Income			Fixed-Income			Real Assets		Total
Balance as of January 1, 2011	$	47		$	129		$	10			-	$	186
Actual return on plan assets:
Relating to assets still held at the reporting date		1			16			-			-		17
Relating to assets sold during the period		-			(2	)		-			-		(2	)
Purchases, issuances, sales, and settlements
Purchases		-			34			-			6		40
Settlements		(1	)		(30	)		(5	)		-		(36	)
Transfers out of Level 3		-			(146	)		(5	)		-		(151	)
Balance as of December 31, 2011	$	47		$	1		$	-		$	6	$	54
Actual return on plan  assets:
Relating to assets still held at the reporting date		2			-			-			1		3
Relating to assets sold during the period		-			-			-			-		-
Purchases, issuances, sales, and settlements
Purchases		-			1			-			21		22
Settlements		-			(1	)		-			-		(1	)
Balance as of December 31, 2012	$	49		$	1		$	-		$	28	$	78

                There were no transfers out of Level 3 in 2012.

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Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $282 million to the pension benefit plans and $149 million to the other benefit plans in 2012.  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 2012.  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 $327 million and $109 million to the pension plan and other postretirement benefit plans, respectively, for 2013.

Benefits Payments and Receipts

As of December 31, 2012, the estimated benefits PG&E Corporation is expected to pay and federal subsidies it is estimated to receive in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter for PG&E Corporation, are as follows:

(in millions)	Pension		Other		Federal Subsidy
2013	$	581	$	108	$	(6	)
2014		618		112		(7	)
2015		656		115		(7	)
2016		695		119		(8	)
2017		732		124		(8	)
2018 - 2022		4,172		662		(42	)

There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above.  There were no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.

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,
2012	$	67
2011		65
2010		56

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 Chapter 11 proceeding 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 governmental entities, for overcharges incurred in the CAISO and the PX wholesale electricity markets during this period.  It is uncertain when all these FERC and judicial proceedings will be finally resolved.

While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers.  The Utility entered into a number of settlement agreements 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.  Additional settlement discussions with other electricity suppliers are ongoing.  Any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers through resolution of the remaining disputed claims, either through settlement or through the conclusion of the various FERC and judicial proceedings, are refunded to customers through rates in future periods.

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On April 10, 2012, the Utility received from the PX a letter stating the mutual intent of the CAISO and the PX to offset the Utility’s remaining disputed claims with its accounts receivable from the CAISO and the PX.  Accordingly, the Utility has presented the net amount of remaining disputed claims and accounts receivable on the Consolidated Balance Sheets at December 31, 2012, reflecting its intent and right to offset these amounts.  At December 31, 2011, $494 million was included within accounts receivable – other on the Consolidated Balance Sheets.

The following table presents the changes in the remaining net disputed claims liability, which includes interest:

(in millions)
Balance at December 31, 2011	$	848
Interest accrued		27
Less: supplier settlements		(33	)
Balance at December 31, 2012	$	842

At December 31, 2012, the remaining net disputed claims liability consisted of $157 million of remaining net disputed claims (classified on the Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds) and $685 million of accrued interest (classified on the Consolidated Balance Sheets within interest payable).

At December 31, 2012 and December 31, 2011, the Utility held $291 million and $320 million, respectively, in escrow, including earned interest, for payment of the remaining net disputed claims liability.  These amounts are included within restricted cash on the Consolidated Balance Sheets.

Interest accrues on the remaining net 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 in rates, these collections are not held in escrow.  If the amount of accrued interest is greater than the amount of interest ultimately determined to be owed on the remaining net disputed claims, the Utility would refund to customers any excess interest collected.  The amount of any interest that the Utility may be required to pay will depend on the final determined amount of the remaining net disputed claims and when such interest is paid.

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,
(in millions)	2012			2011			2010
Utility revenues from:
Administrative services provided to PG&E Corporation		$	7		$	6		$	7
Utility expenses from:
Administrative services received from PG&E Corporation		$	50		$	49		$	55
Utility employee benefit due to PG&E Corporation			51			33			27

At December 31, 2012 and 2011, the Utility had receivables of $19 million and $21 million, respectively, from PG&E Corporation included in accounts receivable – other and other noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $17 million and $13 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

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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 regulatory proceedings, nuclear operations, legal matters, environmental remediation, and guarantees.

Commitments

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 natural gas or electricity at the date of delivery.

The costs incurred for all power purchases were as follows:

(in millions)	2012			2011			2010
Qualifying facilities(1)		$	779		$	1,069		$	1,164
Renewable energy contracts			815			622			573
Other power purchase agreements			661			690			657

(1) Costs incurred include $286, $297, and $321 attributable to renewable energy contracts with qualifying facilities at December 31, 2012, 2011 and 2010, respectively.

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 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 electrical output and CPUC-approved energy prices.  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, 2012, the Utility had agreements with 180 QFs that are in operation, which expire at various dates between 2013 and 2028.

Renewable Energy Power Purchase Agreements – The Utility has entered into various contracts to purchase renewable energy to help the Utility meet California’s current renewable portfolio standard (“RPS”) requirement.  California’s RPS program gradually increases the amount of renewable energy that load-serving entities, such as the Utility, must deliver to their customers from an average of at least 20% of their total retail sales in the years 2011-2013 to 33% of their total retail sales in 2021 and thereafter.  Generally these agreements include an energy payment based on the electrical output and a fixed price per Megawatt-hour.  The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities.  The table below includes arrangements that have been approved by the CPUC and have completed major milestones with respect to construction.  The Utility’s commitments for energy payments under these renewable energy agreements are expected to grow significantly, assuming that the facilities are developed timely.

Other Power Purchase Agreements – The Utility has entered into several power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements.  The Utility’s obligation under a portion of these agreements is contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility under tolling agreements.  The Utility also has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

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At December 31, 2012, the undiscounted future expected obligations under power purchase agreements were as follows:

			Renewable
(in millions)	Qualifying Facility		(Other than QF)		Other		Total Payments
2013	$	892	$	1,356	$	846	$	3,094
2014		914		1,843		677		3,434
2015		727		2,038		649		3,414
2016		618		2,054		626		3,298
2017		490		2,053		597		3,140
Thereafter		2,238		30,958		3,322		36,518
Total	$	5,879	$	40,302	$	6,717	$	52,898

 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 agreements 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.

(in millions)
2013	$	35
2014		27
2015		24
2016		22
2017		18
Thereafter		20
Total fixed capacity payments		146
Less: amount representing interest		21
Present value of fixed capacity payments	$	125

Minimum lease payments associated with the lease obligations 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 agreements that are treated as capital leases expire between April 2014 and September 2021.

The present value of the fixed capacity payments due under these agreements is recorded on PG&E Corporation’s and the Utility’s Consolidated Balance Sheets.  At December 31, 2012 and 2011, current liabilities – other included $29 million and $36 million, respectively, and noncurrent liabilities – other included $96 million and $212 million, respectively.  The corresponding assets at December 31, 2012 and 2011 of $125 million and $248 million including accumulated amortization of $148 million and $160 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 and to fuel its owned-generation facilities.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, 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 natural gas storage services in northern California in order to more reliably meet customers’ loads.

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At December 31, 2012, the Utility’s undiscounted future expected payment obligations for natural gas supplies, transportation and storage were as follows:

(in millions)
2013	$	707
2014		208
2015		192
2016		152
2017		108
Thereafter		865
Total	$	2,232

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts less than 1 year, amounted to $1.3 billion in 2012, $1.8 billion in 2011, and $1.6 billion in 2010.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements have terms ranging from one to 13 years and are intended to ensure long-term nuclear fuel supply.  The contracts for uranium and for conversion and enrichment services provide for 100% coverage of reactor requirements through 2020, 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.

At December 31, 2012, the undiscounted future expected payment obligations for nuclear fuel were as follows:

(in millions)
2013	$	113
2014		128
2015		194
2016		147
2017		148
Thereafter		878
Total	$	1,608

Payments for nuclear fuel amounted to $118 million in 2012, $77 million in 2011, and $144 million in 2010.

Other Commitments

The Utility has other commitments relating to operating leases.  At December 31, 2012, the future minimum payments related to these commitments were as follows:

(in millions)
2013	$	42
2014		37
2015		32
2016		31
2017		24
Thereafter		206
Total	$	372

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Payments for other commitments relating to operating leases amounted to $32 million in 2012, $27 million in 2011, and $25 million in 2010.  PG&E Corporation and the Utility had operating leases on office facilities expiring at various dates from 2013 to 2023.  Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 2% to 5%.  The rentals payable under these leases may increase by a fixed amount each year, a percentage of increase over base year, or the consumer price index.  Most leases contain extension options ranging between one and five years.

Underground Electric Facilities

At December 31, 2012, the Utility was committed to spending approximately $277 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 $86 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 that the amount of the capital expenditures will be recoverable from customers through rates.

Contingencies

Legal and Regulatory Contingencies

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 laws and regulations.

PG&E Corporation and the Utility record a provision for a loss when it is both probable that a loss 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 losses and record a provision 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 (or reasonably possible losses in excess of the amounts accrued), 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 the amounts related to such contingencies, PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs.

The accrued liability associated with claims and litigation, regulatory proceedings, penalties, and other legal matters (other than the third-party claims, litigation, and investigations related to natural gas matters that are discussed below) totaled $34 million at December 31, 2012 and $52 million at December 31, 2011 and are 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 and regulatory contingencies would have a material impact on their financial condition, results of operations, or cash flows.

Natural Gas Matters

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 (the “San Bruno accident”).  The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage.  Following the San Bruno accident, various regulatory proceedings, investigations, and lawsuits were commenced.  The Natural Transportation Safety Board, an independent review panel appointed by the CPUC, and the CPUC’s Safety and Enforcement Division (“SED”) completed investigations into the causes of the accident, placing the blame primarily on the Utility.

Pending CPUC Investigations and Enforcement Matters

The CPUC is conducting three investigations pertaining to the Utility’s natural gas operations, which are described below.  In 2012, the SED issued reports in each of these investigations alleging that the Utility committed numerous violations of applicable laws and regulations and recommending that the CPUC impose penalties on the Utility.  (See “Penalties Conclusion” below.)  Although the Utility, the SED, and other parties have engaged in settlement discussions in an effort to reach a stipulated outcome to resolve the investigations, the parties have not reached an agreement.  PG&E Corporation and the Utility are uncertain whether or when any stipulated outcome might be reached.  Any agreement regarding a stipulated outcome would be subject to CPUC approval.

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The CPUC has concluded evidentiary hearings in each investigation.  The CPUC administrative law judges (“ALJs”) who oversee the investigations have adopted a revised procedural schedule, including the dates by which the parties’ briefs must be submitted.  The ALJs have also permitted the other parties (the City of San Bruno, The Utility Reform Network, and the City and County of San Francisco) to separately address in their opening briefs their allegations against the Utility, if any, in addition to the allegations made by the SED.  The ALJs have ordered the SED and other parties to file single coordinated briefs to address potential monetary penalties and remedies (which could include remedial operational or policy measures) for all three investigations by April 26, 2013.  After briefing has been completed, the ALJs will issue one or more presiding officer’s decisions listing the violations determined to have been committed, the amount of penalties, and any required remedial actions.  Based on the revised procedural schedule, one or more presiding officer’s decisions will be issued by July 23, 2013.  The decisions would become the final decisions of the CPUC thirty days after issuance unless the Utility or another party filed an appeal, or a CPUC commissioner requested review of the decision, within such time.

CPUC Investigation Regarding the Utility’s Facilities Records for its Natural Gas Pipelines

In February 2011, the CPUC commenced an investigation pertaining to safety recordkeeping for Line 132, as well as for the Utility’s entire gas transmission system.  Among other matters, the investigation will determine whether the San Bruno accident would have been preventable by the exercise of safe procedures and /or accurate and technical recordkeeping in compliance with the law.  In March 2012, the SED submitted testimony alleging that the Utility committed numerous violations of applicable laws and regulations based on the findings of the SED’s records management consultant and an engineering consultant.  Among other findings, the consultants’ reports concluded that: the Utility’s recordkeeping practices have been deficient and have diminished pipeline safety; the San Bruno accident may have been prevented had the Utility managed its records properly over the years; and that the Utility has been operating, and continues to operate, without a functional integrity management program.  The Utility submitted testimony to the CPUC that acknowledged that improvements are needed to its asset management system and recordkeeping practices, but disputed many of the SED’s findings and allegations.  The CPUC concluded evidentiary hearings in this investigation in January 2013.  Briefing on the issue of alleged violations is scheduled to be completed on April 19, 2013.

CPUC Investigation Regarding the Utility’s Class Location Designations for Pipelines

             In November 2011, the CPUC commenced an investigation pertaining to the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density.  Under federal and state regulations, the class location designation of a pipeline is based on the types of buildings, population density, or level of human activity near the segment of pipeline, and is used to determine the maximum allowable operating pressure up to which a pipeline can be operated.  In its May 2012 investigative report, the SED cited the Utility’s admissions in previous reports to the CPUC that it had failed to classify pipeline segments properly and to document past patrols of transmission lines and concluded that these failures resulted in over three thousand violations of state and federal standards.  On July 23, 2012, the Utility submitted testimony in response to the SED’s report that acknowledged deficiencies in the Utility’s past class location and patrol processes and described the efforts to improve those processes.  The CPUC concluded evidentiary hearings in this investigation in September 2012 and briefing on the issue of alleged violations has been completed.

CPUC Investigation Regarding the San Bruno Accident

In January 2012, the CPUC commenced an investigation to determine whether the Utility violated applicable laws and requirements in connection with the San Bruno accident, as alleged by the SED.  In its January investigative report, the SED alleged that the San Bruno accident was caused by the Utility’s failure to follow accepted industry practice when installing the section of pipe that failed, the Utility’s failure to comply with federal pipeline integrity management requirements, the Utility’s inadequate record keeping practices, deficiencies in the Utility’s data collection and reporting system, the Utility’s inadequate procedures to handle emergencies and abnormal conditions, the Utility’s deficient emergency response actions after the incident, and a systemic failure of the Utility’s corporate culture that emphasized profits over safety.  The CPUC stated that the scope of the investigation will include all past operations, practices and other events or courses of conduct that could have led to or contributed to the San Bruno accident, as well as, the Utility’s compliance with CPUC orders and resolutions issued since the date of the San Bruno accident.

The Utility submitted testimony to the CPUC that acknowledged its liability for the San Bruno accident and, based on testimony from an expert witness, stated that the likely root cause of the pipeline rupture was: (1) a missing interior weld on the pipe; (2) a ductile tear on the pipe likely caused by a hydrostatic test performed in 1956 at too low a pressure to cause the defective weld to fail; and (3) a fatigue crack on the pipe that grew over time.  However, the Utility stated that many of the findings identified in the SED’s reports are not deficiencies, or are much less severe than alleged, and do not constitute violations of applicable laws and regulations.  The CPUC concluded evidentiary hearings in this investigation in January 2013.  Briefing on the issue of alleged violations is scheduled to be completed on April 12, 2013.

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Other Potential Enforcement Matters

California gas corporations are required to provide notice to the CPUC of any self-identified or self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and the corporations’ natural gas operating practices.  The CPUC has authorized the SED to issue citations and impose penalties based on self-reported violations.  In April 2012, the CPUC affirmed a $17 million penalty that had been imposed by the SED based on the Utility’s self-report that it failed to conduct periodic leak surveys because it had not included 16 gas distribution maps in its leak survey schedule.  (The Utility has paid the penalty and completed all of the missed leak surveys.)  As of December 31, 2012, the Utility has submitted 34 self-reports with the CPUC, plus additional follow-up reports.  The SED has not yet taken formal action with respect to the Utility’s other self-reports.  The SED may issue additional citations and impose penalties on the Utility associated with these or future reports that the Utility may file.  (See “Penalties Conclusion” below.)

In addition, in July 2012, the Utility reported to the CPUC that it had discovered that its access to some pipelines has been limited by vegetation overgrowth or building structures that encroach upon some of the Utility’s gas pipeline rights-of-way.  The Utility is undertaking a system-wide effort to identify and remove encroachments from its pipeline rights-of-way over a multi-year period.  PG&E Corporation and the Utility are uncertain how this matter will affect the above investigative proceedings related to natural gas operations, or whether additional proceedings or investigations will be commenced that could result in regulatory orders or the imposition of penalties on the Utility.

Penalties Conclusion

The CPUC can impose penalties of up to $20,000 per day, per violation.  (For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation.)  The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged.  The CPUC has historically exercised this wide discretion in determining penalties.  The CPUC's delegation of enforcement authority to the SED allows the SED to use these factors in exercising discretion to determine the number of violations, but the SED is required to impose the maximum statutory penalty for each separate violation that the SED finds.

The CPUC has stated that it is prepared to impose significant penalties on the Utility if the CPUC determines that the Utility violated applicable laws, rules, and orders.  In determining the amount of penalties the ALJs may consider the testimony of financial consultants engaged by the SED and the Utility.  The SED’s financial consultant prepared a report concluding that PG&E Corporation could raise approximately $2.25 billion through equity issuances, in addition to equity PG&E Corporation had already forecasted it would issue in 2012, to fund CPUC-imposed penalties on the Utility.  The Utility’s financial consultant disagreed with this financial analysis and asserted that a fine in excess of financial analysts’ expectations, which the consultant’s report cited as a mean of $477 million, would make financing more difficult and expensive.   The ALJs have scheduled a hearing to be held on March 4 and March 5, 2013 to consider the SED’s and Utility’s testimony.  The SED and other parties are scheduled to file briefs to address potential monetary penalties and remedies in all three investigations by April 26, 2013.

PG&E Corporation and the Utility believe it is probable that the Utility will incur penalties of at least $200 million in connection with these pending investigations and potential enforcement matters and have accrued this amount in their consolidated financial statements.  PG&E Corporation and the Utility are unable to make a better estimate of probable losses or estimate the range of reasonably possible losses in excess of the amount accrued due to the many variables that could affect the final outcome of these matters and the ultimate amount of penalties imposed on the Utility could be materially higher than the amount accrued.  These variables include how the CPUC and the SED will exercise their discretion in calculating the amount of penalties, including how the total number of violations will be counted; how the duration of the violations will be determined; whether the amount of penalties in each investigation will be determined separately or in the aggregate; how the financial resources testimony submitted by the SED and the Utility will be considered; whether the Utility’s costs to perform any required remedial actions will be considered; and whether and how the financial impact of non-recoverable costs the Utility has already incurred, and will continue to incur, to improve the safety and reliability of its pipeline system, will be considered.  (See “CPUC Gas Safety Rulemaking Proceeding” below.)

These estimates, and the assumptions on which they are based, are subject to change based on many factors, including rulings, orders, or decisions that may be issued by the ALJs; whether the outcome of the investigations is resolved through a fully litigated process or a stipulated outcome that is approved by the CPUC; whether the SED will take additional action with respect to the Utility’s self-reports; and whether the CPUC or the SED takes any action with respect to the encroachment matter described above.  Future changes in these estimates or the assumptions on which they are based could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

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CPUC Gas Safety Rulemaking Proceeding

The CPUC is conducting a rulemaking proceeding to adopt new safety and reliability regulations for natural gas transmission and distribution pipelines in California and the related ratemaking mechanisms.  On December 20, 2012, the CPUC approved the Utility’s proposed pipeline safety enhancement plan (filed in August 2011) to modernize and upgrade its natural gas transmission system but disallowed the Utility’s request for rate recovery of a significant portion of plan-related costs the Utility forecasted it would incur over the first phase of the plan (2011 through 2014).  The CPUC decision limited the Utility’s recovery of capital expenditures to $1.0 billion of the total $1.4 billion requested.  Various parties have asked the CPUC to reconsider its decision, arguing that the Utility’s cost recovery should be more limited.  For 2012, the Utility recorded a $353 million charge to net income for plan-related capital expenditures incurred that are forecasted to exceed the CPUC’s authorized levels or that were specifically disallowed.  Future disallowed amounts will be charged to net income in the period incurred and could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Criminal Investigation

In June 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident.  Federal and state authorities have indicated that the Utility is a target of the investigation.  The Utility is cooperating with the investigation.  PG&E Corporation and the Utility are uncertain whether any criminal charges will be brought against either company or any of their current or former employees.  PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Utility as a consequence of this investigation.

Third-Party Claims

In addition to the investigations and proceedings discussed above, at December 31, 2012, approximately 140 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, had been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 450 plaintiffs.  The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages.  These cases were coordinated and assigned to one judge in the San Mateo County Superior Court.  Many of the plaintiffs’ claims have been resolved through settlements. The trial of the first group of remaining cases began on January 2, 2013 with pretrial motions and hearings. On January 14, 2013, the court vacated the trial and all pending hearings due to the significant number of cases that have been settled outside of court.  The court has urged the parties to settle the remaining cases.  As of February 8, 2013, the Utility has entered into settlement agreements to resolve the claims of approximately 140 plaintiffs.  It is uncertain whether or when the Utility will be able to resolve the remaining claims through settlement.    

At December 31, 2012, the Utility had recorded cumulative charges of $455 million for estimated third-party claims related to the San Bruno accident, including an $80 million charge made during 2012, primarily to reflect settlements and information exchanged by the parties during the settlement and discovery process.  The Utility estimates it is reasonably possible that it may incur as much as an additional $145 million for third-party claims, for a total possible loss of $600 million.  PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with punitive damages, if any, related to these matters.  The Utility has publicly stated that it is liable for the San Bruno accident and will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident.

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The following table presents changes in third-party claims activity since the San Bruno accident in 2010; the balance is included in other current liabilities in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

(in millions)
Balance at January 1, 2010	$	-
Loss accrued		220
Less: Payments		(6	)
Balance at December 31, 2010		214
Additional loss accrued		155
Less: Payments		(92	)
Balance at December 31, 2011		277
Additional loss accrued		80
Less: Payments		(211	)
Balance at December 31, 2012	$	146

Additionally, the Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or “layers.”  Generally, as the policy limit for a layer is exhausted the next layer of insurance becomes available.  The aggregate amount of insurance coverage for third-party liability attributable to the San Bruno accident is approximately $992 million in excess of a $10 million deductible.  The Utility has recognized cumulative insurance recoveries for third-party claims of $284 million, which included $185 million for 2012 and $99 million for 2011.  Although the Utility believes that a significant portion of costs incurred for third-party claims relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries.

Class Action Complaint

On August 23, 2012, a complaint was filed in the San Francisco Superior Court against PG&E Corporation and the Utility (and other unnamed defendants) by individuals who seek certification of a class consisting of all California residents who were customers of the Utility between 1997 and 2010, with certain exceptions.  The plaintiffs allege that the Utility collected more than $100 million in customer rates from 1997 through 2010 for the purpose of various safety measures and operations projects but instead used the funds for general corporate purposes such as executive compensation and bonuses.  To state their claims, the plaintiffs cited the SED’s January 2012 investigative report of the San Bruno accident that alleged, from 1996 to 2010, the Utility spent less on capital expenditures and operations and maintenance expense for its natural gas transmission operations than it recovered in rates, by $95 million and $39 million, respectively.  The SED recommended in that report that the Utility should use such amounts to fund future gas transmission expenditures and operations.  Plaintiffs allege that PG&E Corporation and the Utility engaged in unfair business practices in violation of Section 17200 of the California Business and Professions Code (“Section 17200”) and claim that this violation also constitutes a violation of California Public Utilities Code Section 2106 (“Section 2106”), which provides a private right of action for violations of the California constitution or state laws by public utilities.  Plaintiffs seek restitution and disgorgement under Section 17200 and compensatory and punitive damages under Section 2106. 

PG&E Corporation and the Utility contest the plaintiffs’ allegations.  In January 2013, PG&E Corporation and the Utility requested that the court dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs’ allegations.  In the alternative, PG&E Corporation and the Utility requested that the court stay the proceeding until the CPUC investigations described above are concluded.  The court has set a hearing on the motion for April 26, 2013.  Due to the early stage of this proceeding, PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses that may be incurred in connection with this matter.

Spent Nuclear Fuel Storage Proceedings

Under the Nuclear Waste Policy Act of 1982, the DOE and electric utilities with commercial nuclear power plants were authorized to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste by January 1998, in exchange for fees paid by the utilities.  The DOE has been unable to meet its contractual obligation to 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 (“Humboldt Bay Unit 3”).  As a result, the Utility constructed an interim dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024, and a separate facility at Humboldt Bay.  The Utility and other nuclear power plant owners sued the DOE to recover the costs that they incurred to construct interim storage facilities for spent nuclear fuel. 

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On September 5, 2012, the U.S. Department of Justice and the Utility executed a settlement agreement that awarded the Utility $266 million for spent fuel storage costs incurred through December 31, 2010.  As of December 31, 2012, the Utility has collected the settlement proceeds from the U.S. Treasury and recorded the amount as a regulatory balancing account.  The proceeds will be refunded to customers through rates in future periods. The agreement also allows the Utility to submit annual claims to recover costs incurred in 2011, 2012 and 2013, which the Utility estimates to be approximately $25 million per year.  These amounts will also be refunded to customers in future periods.  At December 31, 2012, PG&E Corporation and the Utility have not recorded any receivables for annual claims in their Consolidated Balance Sheets.  The agreement does not address costs incurred for spent fuel storage after 2013 and such costs could be the subject of future litigation.  Considerable uncertainty continues to exist regarding when and whether the DOE will meet its contractual obligation to the Utility and other nuclear power plant owners to dispose of spent nuclear fuel.

Nuclear Insurance

The Utility is a member of Nuclear Electric Insurance Limited (“NEIL”) which is a mutual insurer owned by utilities with nuclear facilities.  NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility due to a nuclear event (meaning that nuclear material is released) that occurs at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident ($2.7 billion for property damage and $490 million for business interruption) for Diablo Canyon.  In addition, NEIL provides $131 million of coverage for nuclear and non-nuclear property damages at Humboldt Bay Unit 3.  (NEIL also provides insurance coverage to the Utility for non-nuclear property damages and business interruption losses at Diablo Canyon, though with significantly lower limits beginning in April 2013.)  Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss, the Utility may be required to pay an additional premium of up to $44 million per one-year policy term.  NRC regulations require that the Utility’s property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident and, second, to decontaminate the plant before any proceeds can be used for decommissioning or plant repair.

NEIL policies also provide coverage for damages caused by acts of terrorism at nuclear power plants.  Certain acts of terrorism may be “certified” by the Secretary of the Treasury.  If damages are 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.  In contrast, NEIL would treat all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share the $3.2 billion policy limit amount.

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 insurance policies.  The Utility has a separate supplier’s and transporter’s policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident.

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.

If the Utility incurs losses in connection with any of its nuclear generation facilities that are either not covered by insurance or exceed the amount of insurance available, such losses could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Environmental Remediation Contingencies

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 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.

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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 the Utility can reasonably estimate the loss or a range of probable amounts.  The Utility records an environmental remediation liability based on the lower end of the range of estimated probable 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 following table presents the changes in the environmental remediation liability:

(in millions)
Balance at December 31, 2011	$	785
Additional remediation costs accrued:
Transfer to regulatory account for  recovery		150
Amounts not recoverable from customers		150
Less: Payments		(175	)
Balance at December 31, 2012	$	910

The environmental remediation liability is composed of the following:

	Balance at December 31,
(in millions)	2012		2011
Utility-owned natural gas compressor site near Hinkley, California (1)	$	226	$	149
Utility-owned natural gas compressor site near Topock, Arizona (1)		239		218
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites		158		133
Former manufatured gas plant sites owned by the Utility or third parties		181		154
Fossil fuel-fired generation facilities formerly owned by the Utility		87		81
Decommissioning fossil fuel-fired generation facilities and sites		19		50
Total environmental remediation liability	$	910	$	785

(1) See “Natural Gas Compressor Site” below.

The CPUC has authorized the Utility to recover most of its environmental remediation costs through various ratemaking mechanisms, subject to exclusions for certain sites, such as the Hinkley natural gas compressor site, and subject to limitations for certain liabilities such as amounts associated with fossil fuel-fired generation facilities formerly owned by the Utility.  At December 31, 2012, the Utility expected to recover $548 million through these ratemaking mechanisms.  The Utility also recovers environmental remediation costs from insurance carriers and from other third parties whenever possible.  Amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers through rates.

Natural Gas Compressor Sites

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor sites near Hinkley, California (“Hinkley site”) and Topock, Arizona (“Topock site”).  The Utility is also required to take measures to abate the effects of the contamination on the environment.

Hinkley Site

The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region (“Regional Board”).  The Regional Board has issued several orders directing the Utility to implement interim remedial measures to reduce the mass of the underground plume of hexavalent chromium, monitor and control movement of the plume, and provide replacement water to affected residents.

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The Utility submitted its proposed final remediation plan to the Regional Board in September 2011 recommending a combination of remedial methods to clean up groundwater contamination, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water.  In August 2012, the Regional Board issued a draft environmental impact report (“EIR”) that evaluated the Utility’s proposed methods and the potential environmental impacts.  The Utility expects that the Regional Board will consider certification of the final EIR in the second quarter of 2013.  Upon certification of the EIR, the Regional Board is expected to issue the final cleanup standards in late 2013.

The Regional Board ordered the Utility in October 2011 to provide an interim and permanent replacement water system for resident households located near the chromium plume that have domestic wells containing hexavalent chromium in concentrations greater than 0.02 parts per billion.  The Utility filed a petition with the California State Water Resources Control Board to contest certain provisions of the order.  In June 2012, the Regional Board issued an amended order to allow the Utility to implement a whole house water replacement program for resident households located near the chromium plume boundary.  Eligible residents may decide whether to accept a replacement water supply or have the Utility purchase their properties, or alternatively not participate in the program.  As of January 31, 2013, approximately 350 residential households are covered by the program and the majority have opted to accept the Utility’s offer to purchase their properties.  The Utility is required to complete implementation of the whole house water replacement systems by August 31, 2013.  The Utility will maintain and operate the whole house replacement systems for five years or until the State of California has adopted a drinking water standard specifically for hexavalent chromium at which time the program will be evaluated.

At December 31, 2012 and 2011, $226 million and $149 million, respectively, were accrued in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley site.  The increase primarily reflects the Utility’s best estimate of costs associated with the developments described above.  Remediation costs for the Hinkley natural gas compressor site are not recovered from customers through rates.  Future costs will depend on many factors, including the Regional Board’s certification of the final EIR, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the Utility’s required time frame for remediation, and adoption of a final drinking water standard currently under development by the State of California, as mentioned above.  As more information becomes known regarding these factors, these estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to further changes.  Future changes in estimates or assumptions may have a material impact on PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows. 

Topock Site

The Utility’s remediation and abatement efforts are subject to the regulatory authority of the Department of Toxic Substances Control (“DTSC”) and the U.S. Department of the Interior (“DOI”).  As directed by the DTSC, 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.  The DTSC has certified the final EIR and approved the Utility’s final remediation plan for the groundwater plume, under which the Utility will implement an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium.  The Utility has completed the preliminary design stage for implementing the final groundwater remedy and is required to submit its intermediate design plan to the DTSC and DOI by April 5, 2013 and a final plan for approval in 2014.  In developing its intermediate plan, the Utility is currently evaluating input received from regulatory agencies and other stakeholders, exploring potential sources of fresh water to be used as part of the remedy, and performing other engineering activities necessary to complete the remedial design.

At December 31, 2012 and 2011, $239 million and $218 million, respectively, were accrued in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Topock site.  The CPUC has authorized the Utility to recover 90% of its remediation costs for the Topock site from customers through rates without a reasonableness review.  As the Utility completes its remedial design plan and more information becomes known regarding the extent of work to be performed to implement the final groundwater remedy, these estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to change.  Future changes in estimates or assumptions could have a material impact on PG&E Corporation’s and the Utility’s future financial condition.

Reasonably Possible Environmental Contingencies

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility’s undiscounted future costs could increase to as much as $1.6 billion (including amounts related to the Hinkley and Topock sites described above) 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.  The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on PG&E Corporation’s and the Utility’s results of operations during the period in which they are recorded.

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QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)

	Quarter ended
(in millions, except per share amounts)	December 31			September 30		June 30		March 31
2012
PG&E CORPORATION
Operating revenues	$	3,830		$	3,976	$	3,593	$	3,641
Operating income		125			614		467		487
Net income (loss)		(9	)		364		239		236
Income (loss) available for common shareholders		(13	)		361		235		233
Net earnings (loss) per common share, basic		(0.03	)		0.84		0.56		0.56
Net earnings (loss) per common share, diluted		(0.03	)		0.84		0.55		0.56
Common stock price per share:
High		43.48			46.51		45.20		43.72
Low		39.71			42.41		42.04		40.16
UTILITY
Operating revenues	$	3,829		$	3,974	$	3,592	$	3,640
Operating income		127			613		467		488
Net income		13			340		227		231
Income available for common stock		9			337		223		228
2011
PG&E CORPORATION
Operating revenues	$	3,815		$	3,860	$	3,684	$	3,597
Operating income		358			408		692		484
Net income		87			203		366		202
Income available for common shareholders		83			200		362		199
Net earnings per common share, basic		0.20			0.50		0.91		0.50
Net earnings per common share, diluted		0.20			0.50		0.91		0.50
Common stock price per share:
High		43.24			43.32		46.52		47.60
Low		36.86			39.21		41.39		42.47
UTILITY
Operating revenues	$	3,813		$	3,859	$	3,683	$	3,596
Operating income		359			402		699		484
Net income		89			196		359		201
Income available for common stock		85			193		355		198

During the fourth quarter 2012, the Utility recorded a charge to net income of $353 million for disallowed capital expenditures associated with the Utility's pipeline safety enhancement plan.  See Note 15 of the Notes to the Consolidated Financial Statements.

During the second quarter 2012 the Utility recorded a provision of $80 million for estimated third-party claims related to the San Bruno accident.  During the first quarter 2012, second quarter of 2012, third quarter of 2012, and fourth quarter 2012, the Utility submitted insurance claims to certain insurers for the lower layers and recognized $11 million, $25 million, $99 million, and $50 million, respectively, for insurance recoveries.  See Note 15 of the Notes to the Consolidated Financial Statements.

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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, 2012, 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, 2012.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

114

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, 2012 and 2011, and the Company’s related consolidated statements of income, comprehensive income, equity, and cash flows and the Utility’s related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's and the Utility’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of PG&E Corporation and subsidiaries and of Pacific Gas and Electric Company and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 15 to the consolidated financial statements, several investigations and enforcement matters are pending with the California Public Utilities Commission and may result in material amounts of penalties.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's and the Utility’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2013 expressed an unqualified opinion on the Company's and the Utility’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 21, 2013

115

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 internal control over financial reporting of PG&E Corporation and subsidiaries (the "Company") and of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2012, 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 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 the Company’s and the Utility's internal control over financial reporting based on our audits.

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

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 Company and the Utility maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Company and the Utility and our report dated February 21, 2013 expressed an unqualified opinion on those financial statements and includes an explanatory paragraph relating to several investigations and enforcement matters pending with the California Public Utilities Commission that may result in material amounts of penalties.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 21, 2013

116

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 Statement No. 333-172393 on Form S-3, 333-144498 on Form S-3D, and 333-73054, 333-129422, and 333-176090 on Form S-8 of PG&E Corporation and Registration Statements No. 33-62488 and 333-172394 on Form S-3 of Pacific Gas and Electric Company of our reports dated February 21, 2013, relating to the consolidated financial statements (which report expresses an unqualified opinion and includes an explanatory paragraph relating to several investigations and enforcement matters pending with the California Public Utilities Commission that may result in material amounts of penalties), the 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, 2012.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 21, 2013

EX-24

Exhibit 24

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 A. 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, 2012 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 20th day of February, 2013.

	ROGER H. KIMMEL
David R. Andrews LEWIS CHEW	Roger H. Kimmel RICHARD A. MESERVE
Lewis Chew C. LEE COX	Richard A. Meserve FORREST E. MILLER
C. Lee Cox ANTHONY F. EARLEY, JR.	Forrest E. Miller ROSENDO G. PARRA
Anthony F. Earley, Jr. FRED J. FOWLER	Rosendo G. Parra BARBARA L. RAMBO
Fred J. Fowler MARYELLEN C. HERRINGER	Barbara L. Rambo BARRY LAWSON WILLIAMS
Maryellen C. Herringer	Barry Lawson Williams

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 A. 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, 2012 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 20th day of February, 2013.

	ROGER H. KIMMEL
David R. Andrews LEWIS CHEW	Roger H. Kimmel RICHARD A. MESERVE
Lewis Chew C. LEE COX	Richard A. Meserve FORREST E. MILLER
C. Lee Cox ANTHONY F. EARLEY, JR.	Forrest E. Miller ROSENDO G. PARRA
Anthony F. Earley, Jr. FRED J. FOWLER	Rosendo G. Parra BARBARA L. RAMBO
Fred J. Fowler MARYELLEN C. HERRINGER	Barbara L. Rambo BARRY LAWSON WILLIAMS
Maryellen C. Herringer CHRISTOPHER P. JOHNS	Barry Lawson Williams
Christopher P. Johns

EX-31.01

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Anthony F. Earley, Jr., certify that:

1. I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2012 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 21, 2013	ANTHONY F. EARLEY, JR.
	Anthony F. Earley, Jr.
	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, 2012 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 21, 2013	KENT M. HARVEY
	Kent M. Harvey
	Senior Vice President and Chief Financial Officer

EX-31.02

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, 2012 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 21, 2013	CHRISTOPHER P. JOHNS
	Christopher P. Johns
	President

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Dinyar B. Mistry, certify that:

1. I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2012 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 21, 2013	DINYAR B. MISTRY
	Dinyar B. Mistry
	Vice President, Chief Financial Officer and Controller

EX-32.01

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, 2012 (“Form 10-K”), I, Anthony F. Earley, Jr., 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.

ANTHONY F. EARLEY, JR.

ANTHONY F. EARLEY, JR.

Chairman, Chief Executive Officer, and President

February 21, 2013

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, 2012 (“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 21, 2013

EX-32.02

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, 2012 (“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 21, 2013

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, 2012 (“Form 10-K”), I, Dinyar B. Mistry, Vice President, Chief Financial Officer and Controller 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.

DINYAR B. MISTRY

DINYAR B. MISTRY

Vice President, Chief Financial Officer and Controller

February 21, 2013

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Resolution Of Remaining Chapter 11 Disputed Claims (Tables)

12 Months Ended

Dec. 31, 2012

Resolution Of Remaining Chapter 11 Disputed Claims [Abstract]

Changes In The Remaining Net Disputed Claims Liability

(in millions)
Balance at December 31, 2011	$	848
Interest accrued		27
Less: supplier settlements		(33)
Balance at December 31, 2012	$	842

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Schedule II - Consolidated Valuation And Qualifying Accounts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Schedule II - Consolidated Valuation And Qualifying Accounts [Abstract]
Allowance for uncollectible accounts, Balance at Beginning of Period	$ 81	[1]	$ 81	[1]	$ 68	[1]
Allowance for uncollectible accounts, Charged to Costs and Expenses	66	[1]	60	[1]	56	[1]
Charged to other accounts	0	[1]	0	[1]	0	[1]
Allowance for uncollectible accounts, Deductions	60	[1],[2]	60	[1],[2]	43	[1],[2]
Allowance for uncollectible accounts, Balance at End of Period	$ 87	[1]	$ 81	[1]	$ 81	[1]

[1] Allowance for uncollectible accounts is deducted from "Accounts receivable - Customers."

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

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Debt (Schedule Of Long-Term Debt Repayments) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Debt [Line Items]
Total consolidated long-term debt	$ 12,968
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	5.75%
Fixed rate obligations	350
Utility [Member]
Debt [Line Items]
Average fixed interest rate	5.43%
Fixed rate obligations	11,695
Variable interest rate as of December 31, 2012	0.11%
Total consolidated long-term debt	923
2013 [Member]
Debt [Line Items]
Total consolidated long-term debt	400
2013 [Member] | Utility [Member]
Debt [Line Items]
Average fixed interest rate	6.25%
Fixed rate obligations	400
2014 [Member]
Debt [Line Items]
Total consolidated long-term debt	1,350
2014 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	5.75%
Fixed rate obligations	350
2014 [Member] | Utility [Member]
Debt [Line Items]
Average fixed interest rate	4.80%
Fixed rate obligations	1,000
2015 [Member]
Debt [Line Items]
Total consolidated long-term debt	0
2015 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	0
2015 [Member] | Utility [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	0
Variable interest rate as of December 31, 2012	0.00%
Total consolidated long-term debt	0
2016 [Member]
Debt [Line Items]
Total consolidated long-term debt	923
2016 [Member] | Utility [Member]
Debt [Line Items]
Variable interest rate as of December 31, 2012	0.11%
Total consolidated long-term debt	923	[1]
2017 [Member]
Debt [Line Items]
Total consolidated long-term debt	700
2017 [Member] | Utility [Member]
Debt [Line Items]
Average fixed interest rate	5.63%
Fixed rate obligations	700
Thereafter [Member]
Debt [Line Items]
Total consolidated long-term debt	9,595
Thereafter [Member] | Utility [Member]
Debt [Line Items]
Average fixed interest rate	5.45%
Fixed rate obligations	$ 9,595

[1] These bonds, due in 2016 and 2026, are backed by letters of credit that expire on May 31, 2016.

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Regulatory Assets, Liabilities, And Balancing Accounts (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 years months	Dec. 31, 2011
Regulatory Assets [Line Items]
Current regulatory assets	$ 564	$ 1,090
Book value of undepreciated conventional electromechanical meters	54
Deferred income taxes regulatory asset recovery minimum (years)	1
Retained generation regulatory assets	62
Deferred income taxes regulatory asset recovery maximum (years)	45
Utility retained generation asset costs	1,200
Weighted average remaining life of Utility retained generation assets (years)	12
Environmental compliance costs regulatory asset recovery (years)	32
Price risk management regulatory assets recovery (years)	10
Expected recovery of regulated assets (years)	4
Recovery of costs related to debt reacquired or redeemed prior to maturity (years)	14
Current regulatory liabilities	337	161
Period of time expected to receive authorized rate adjustments (months)	12
Period of time exceeded for regulatory balancing accounts to be recorded in other noncurrent assets (months)	12
Recovery of energy procurement costs, percentage	100.00%
Greenhouse gas auction proceeds	84
Electric supplier settlement agreement	50
Period Of Time Expected To Refund Regulatory Liabilities To Customers	12
Period Of Time Expected To Incur Public Purpose Program Costs Minimum	12
Energy Recovery Bonds [Member]
Regulatory Assets [Line Items]
Current regulatory liabilities	158
Price Risk Management Derivative Instruments [Member]
Regulatory Assets [Line Items]
Current regulatory assets	$ 230

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Derivatives And Hedging Activities (Volumes Of Outstanding Derivative Contracts) (Details)	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Derivative [Line Items]
Derivatives expiration, lower	2018 years		2017 years
Derivatives expiration, higher	2023 years		2022 years
Forwards And Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Less Than 1 Year	329,466,510	[1],[2],[3]	500,375,394
Greater Than 1 Year but Less Than 3 Years	98,628,398	[1],[2],[3]	212,088,902
Greater Than 3 Years but Less Than 5 Years	5,490,000	[1],[2],[3]	6,080,000
Greater Than 5 Years	0	[1],[2],[3],[4]	0	[1],[2],[3],[5]
Forwards And Swaps [Member] | Electricity [Member]
Derivative [Line Items]
Less Than 1 Year	2,537,023	[1]	4,718,568	[1]
Greater Than 1 Year but Less Than 3 Years	3,541,046	[1]	5,206,512	[1]
Greater Than 3 Years but Less Than 5 Years	2,009,505	[1]	2,142,024	[1]
Greater Than 5 Years	2,538,718	[1],[4]	3,754,872	[1],[5]
Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Less Than 1 Year	221,587,431	[1]	257,766,990	[1]
Greater Than 1 Year but Less Than 3 Years	216,279,767	[1]	336,543,013	[1]
Greater Than 3 Years but Less Than 5 Years	10,050,000	[1]	0	[1]
Greater Than 5 Years	0	[1],[4]	0	[1],[5]
Options [Member] | Electricity [Member]
Derivative [Line Items]
Less Than 1 Year	0	[1]	1,248,000	[1]
Greater Than 1 Year but Less Than 3 Years	239,015	[1]	132,048	[1]
Greater Than 3 Years but Less Than 5 Years	239,233	[1]	264,348	[1]
Greater Than 5 Years	119,508	[1],[4]	264,096	[1],[5]
Congestion Revenue Rights [Member] | Electricity [Member]
Derivative [Line Items]
Less Than 1 Year	74,198,690	[1]	84,247,502	[1]
Greater Than 1 Year but Less Than 3 Years	74,187,803	[1]	72,882,246	[1]
Greater Than 3 Years but Less Than 5 Years	74,240,147	[1]	72,949,250	[1]
Greater Than 5 Years	25,699,804	[1],[4]	61,673,535	[1],[5]

[1] Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each period.

[2] Amounts shown are for the combined positions of the electric fuels and core gas portfolios.

[3] Million British Thermal Units.

[4] Derivatives in this category expire between 2018 and 2023.

[5] Derivatives in this category expire between 2017 and 2022.

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Debt (Schedule Of Line Of Credit) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 days
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Expiration date for credit agreement	May 31, 2016
Facility Limit	$ 300	[1]
Letters of Credit outstanding	0
Borrowings	120
Commercial Paper	0
Facility Availability	180
Letters of credit, sublimit	100
Swingline loans, sublimit	100
Swingline loan repay term (days)	7
Utility [Member]
Debt [Line Items]
Expiration date for credit agreement	May 31, 2016
Facility Limit	3,000	[2]
Letters of Credit outstanding	266
Borrowings	0
Commercial Paper	370	[3]
Facility Availability	2,364	[3]
Letters of credit, sublimit	1,000
Swingline loans, sublimit	300
Swingline loan repay term (days)	7
Credit Facilities [Member]
Debt [Line Items]
Facility Limit	3,300
Letters of Credit outstanding	266
Borrowings	120
Commercial Paper	370
Facility Availability	$ 2,544

[1] Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.

[2] Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days

[3] The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.

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Fair Value Measurements (Schedule Of Maturities On Debt Securities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Fair Value Measurements [Abstract]
Less than 1 year	$ 5
1-5 years	456
5-10 years	218
More than 10 years	373
Total maturities of debt securities	$ 1,052

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Commitments And Contingencies (Environmental Remediation Contingencies) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$ 548
Eligible Resident Households For Voluntary Program	350
Utility Undiscounted Future Costs	1,600
Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Utility Undiscounted future costs	910	785
Hinkley Natural Gas Compressor Station [Member]
Long-term Purchase Commitment [Line Items]
Utility Undiscounted future costs	$ 226	$ 149

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Summary Of Significant Accounting Policies (Schedule Of Estimated Useful Lives And Balances Of Utility's Property, Plant And Equipment) (Details) (USD $) In Millions, unless otherwise specified							12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Electricity generating facilities [Member] Utility [Member]		Dec. 31, 2011 Electricity generating facilities [Member] Utility [Member]		Dec. 31, 2012 Electricity generating facilities [Member] Utility [Member] Minimum [Member]	Dec. 31, 2012 Electricity generating facilities [Member] Utility [Member] Maximum [Member]	Dec. 31, 2012 Electricity distribution facilities [Member] Utility [Member]	Dec. 31, 2011 Electricity distribution facilities [Member] Utility [Member]	Dec. 31, 2012 Electricity distribution facilities [Member] Utility [Member] Minimum [Member]	Dec. 31, 2012 Electricity distribution facilities [Member] Utility [Member] Maximum [Member]	Dec. 31, 2012 Electricity transmission [Member] Utility [Member]	Dec. 31, 2011 Electricity transmission [Member] Utility [Member]	Dec. 31, 2012 Electricity transmission [Member] Utility [Member] Minimum [Member]	Dec. 31, 2012 Electricity transmission [Member] Utility [Member] Maximum [Member]	Dec. 31, 2012 Natural gas distribution facilities [Member] Utility [Member]	Dec. 31, 2011 Natural gas distribution facilities [Member] Utility [Member]	Dec. 31, 2012 Natural gas distribution facilities [Member] Utility [Member] Minimum [Member]	Dec. 31, 2012 Natural gas distribution facilities [Member] Utility [Member] Maximum [Member]	Dec. 31, 2012 Natural gas transportation and storage [Member] Utility [Member]	Dec. 31, 2011 Natural gas transportation and storage [Member] Utility [Member]	Dec. 31, 2012 Natural gas transportation and storage [Member] Utility [Member] Minimum [Member]	Dec. 31, 2012 Natural gas transportation and storage [Member] Utility [Member] Maximum [Member]	Dec. 31, 2012 Construction Work In Progress [Member] Utility [Member]	Dec. 31, 2011 Construction Work In Progress [Member] Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 54,166	$ 49,552	$ 8,253	[1]	$ 6,488	[1]			$ 23,767	$ 22,395			$ 7,681	$ 6,968			$ 8,257	$ 7,832			$ 4,314	$ 4,099			$ 1,894	$ 1,770
Accumulated depreciation	(16,643)	(15,898)
Net property, plant, and equipment	$ 37,523	$ 33,654
Property, Plant and Equipment, Useful Life							10 years	100 years			10 years	55 years			10 years	70 years			20 years	53 years			5 years	48 years

[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.)

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Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2012

Preferred Stock [Abstract]

Summary Of Issued And Outstanding Preferred Stock

(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

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Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Fair Value Measurements [Abstract]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 1,133	$ 1,928	$ 1,405
Gross realized gains on sales of securities held as available-for-sale	19	43	42
Gross realized losses on sales of securities held as available-for-sale	$ (17)	$ (30)	$ (11)

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Derivatives And Hedging Activities (Additional Cash Collateral The Utility Would Be Required To Post If Its Credit-Risk-Related Contingency Features Were Triggered) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Derivatives And Hedging Activities [Abstract]
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized	$ (266)		$ (611)
Related derivatives in an asset position	59		86
Collateral posting in the normal course of business related to these derivatives	103		250
Net position of derivative contracts/additional collateral posting requirements	$ (104)	[1]	$ (275)	[1]

[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.

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Employee Benefit Plans (Schedule Of Estimated Benefits Expected To Be Paid) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
2013	$ 581
2014	618
2015	656
2016	695
2017	732
2018-2022	4,172
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2013	108
2014	112
2015	115
2016	119
2017	124
2018-2022	662
Contributed to the other benefit plans	149	137
Approximate contribution expected to be paid	109
Federal Subsidy [Member]
Defined Benefit Plan Disclosure [Line Items]
2013	(6)
2014	(7)
2015	(7)
2016	(8)
2017	(8)
2018-2022	(42)
Pensions Benefits Member
Defined Benefit Plan Disclosure [Line Items]
Contributed to the other benefit plans	282
Approximate contribution expected to be paid	$ 327

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Common Stock And Share-Based Compensation (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Feb. 29, 2012	Dec. 31, 2011	Nov. 28, 2011
Common stock, shares outstanding	430,718,293				412,257,082
Common stock shares issued from exercise of employee stock options	6,803,101
Equity distribution agreement, shares issued	5,446,760
Equity distribution agreement amount	$ 234					$ 400
Ability to issuance of additional common stock under equity distribution agreement	64
Dividend per share	$ 0.455	$ 0.455	$ 0.455	$ 0.455
Debt covenant ratio of total consolidated debt to total consolidated capitalization percentage	65.00%
Retained earnings maintained as equity	6,300
Percentage of equity for capital structure to be maintained	52.00%
Sale of common stock in an underwritten public offering	5,900,000
Common stock issued from exercise of employee stock options, amount	263
Common stock issued, amount	254
Utility [Member]
Net restricted assets for revolving credit facility ratio requirement	7,000
Net restricted assets for equity component requirement	12,200
Restricted reinvested earnings	$ 1,100

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Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Income Statement) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating expenses									$ 13,347	$ 13,014	$ 11,533
Interest income									7	7	9
Interest expense									(703)	(700)	(684)
Other income, net									70	49	27
Income Before Income Taxes									1,067	1,298	1,660
Income tax provision									262	440	547
Net Income									816	844	1,099
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
Other (net of income tax of$3 in 2012)									4	0	0
Total other comprehensive income									112	(11)	(42)
Comprehensive income									942	847	1,071
Weighted average common shares outstanding, basic									424	401	382
Weighted average common shares outstanding, diluted									425	402	392
Net earnings per common share, basic									$ 1.92	$ 2.1	$ 2.86
Net earnings per common share, diluted									$ 1.92	$ 2.1	$ 2.82
PG&E Corporation [Member]
Administrative service revenue									43	44	53
Operating expenses									(41)	(44)	(55)
Interest income									1	1	1
Interest expense									(22)	(22)	(35)
Other income, net									(39)	(17)	4
Equity in earnings of subsidiaries									817	852	1,105
Income Before Income Taxes									759	814	1,073
Income tax provision									57	30	26
Net Income	(13)	361	235	233	83	200	362	199	816	844	1,099
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
Pension and other postretirement benefit plans (net of income tax of $72, $9, $25 in 2012, 2011, and 2010 respectivley)									(108)	(11)	(42)
Other (net of income tax of$3 in 2012)									4	0	0
Total other comprehensive income									112	(11)	(42)
Comprehensive income									$ 928	$ 833	$ 1,057
Weighted average common shares outstanding, basic									424	401	382
Weighted average common shares outstanding, diluted									425	402	392
Net earnings per common share, basic	$ (0.03)	$ 0.84	$ 0.56	$ 0.56	$ 0.2	$ 0.5	$ 0.91	$ 0.5	$ 1.92	$ 2.1	$ 2.86
Net earnings per common share, diluted	$ (0.03)	$ 0.84	$ 0.55	$ 0.56	$ 0.2	$ 0.5	$ 0.91	$ 0.5	$ 1.92	$ 2.1	$ 2.82

XML

Fair Value Measurements (Carrying Amount And Fair Value Of Financial Instruments) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Energy recovery bond, principal outstanding		$ 423
Carrying Amount [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	349	349
Energy recovery bond, principal outstanding	0	423
Carrying Amount [Member] | Pacific Gas And Electric Company [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	11,645	10,545
Estimate Of Fair Value [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	371	380
Energy recovery bond, principal outstanding	0	433
Estimate Of Fair Value [Member] | Pacific Gas And Electric Company [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	$ 13,946	$ 12,543

XML

Employee Benefit Plans (Target Asset Allocation Percentages) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target allocation percentage of assets, Total	100.00%	100.00%	100.00%
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target allocation percentage of assets, Total	100.00%	100.00%	100.00%
Fixed Income Securities[Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	60.00%	50.00%	50.00%
Fixed Income Securities[Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	57.00%	47.00%	50.00%
Real Assets [member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	8.00%	8.00%	0.00%
Real Assets [member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	10.00%	10.00%	0.00%
Extended Fixed Income Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	0.00%	0.00%	0.00%
Extended Fixed Income Securities [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	3.00%	3.00%	0.00%
Absolute Return [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	4.00%	4.00%	4.00%
Absolute Return [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	5.00%	5.00%	5.00%
Global Equity Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	28.00%	38.00%	3.00%
Global Equity Securities [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	25.00%	35.00%	5.00%
U.S. Equity Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	0.00%	0.00%	28.00%
U.S. Equity Securities [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	0.00%	0.00%	26.00%
Non-U.S. Equity Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	0.00%	0.00%	15.00%
Non-U.S. Equity Securities [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	0.00%	0.00%	14.00%

XML

Employee Benefit Plans (Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Noncurrent liability	$ (3,575)		$ (3,396)
Accumulated benefit obligation	13,778		12,285
Decrease in other comprehensive income	(17)		(36)		29
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	1,491		1,337
Actual return on plan assets	191		95
Company contributions	149		137
Plan participant contribution	55		52
Benefits and expenses paid	(128)		(130)
Fair value of plan assets at December 31	1,758		1,491		1,337
Projected benefit obligation at January 1	1,885		1,755
Service cost for benefits earned	49		42
Interest cost	83		91		88
Actuarial loss	(23)		63
Plan amendments	5		0
Benefits and expenses paid	(119)		(130)
Federal subsidy on benefits paid	5		12
Projected benefit obligation at December 31	1,940		1,885		1,755
Noncurrent liability	(181)		(394)
Accrued benefit cost	(181)		(394)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	10,993		10,250
Actual return on plan assets	1,488		1,016
Company contributions	282		230
Benefits and expenses paid	(622)		(503)
Fair value of plan assets at December 31	12,141		10,993		10,250
Projected benefit obligation at January 1	14,000	[1]	12,071
Service cost for benefits earned	396		320
Interest cost	658		660		645
Actuarial loss	1,099		1,450
Plan amendments	9		0
Transitional costs	1		2
Benefits and expenses paid	(622)		(503)
Projected benefit obligation at December 31	15,541	[1]	14,000	[1]	12,071
Current liability	(6)		(5)
Noncurrent liability	(3,394)		(3,002)
Accrued benefit cost	(3,400)		(3,007)
Change In Benefit Obligation [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan participant contribution	$ 55		$ 52

[1] PG&E Corporation's accumulated benefit obligation was $13,778 million and $12,285 million at December 31, 2012 and 2011, respectively.

XML

Employee Benefit Plans (Schedule Of Fair Value Of Plan Assets) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	$ 13,767	$ 12,529
Total Fair Value Of Trust Other Net Assets	132
Total Fair Value Of Trust Other Net Liabilities	45
Notice To Redeem Investments days [maximum]	90
Money Market Investments Net Asset Value Per Unit	$ 1
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	1,733	1,524
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	12,034	11,005
Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	420	396
Fair Value, Inputs, Level 1 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	2,618	2,204
Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	1,235	1,074
Fair Value, Inputs, Level 2 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	8,007	7,664
Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	78	54	186
Fair Value, Inputs, Level 3 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	1,409	1,137	1,163
Cash Equivalents [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	77	48
Cash Equivalents [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	112	51
Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	77	48
Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	112	51
Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
U.S. Government And Agency Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	153	151
U.S. Government And Agency Securities [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	1,715	1,396
U.S. Government And Agency Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	148	151
U.S. Government And Agency Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	1,576	1,224
U.S. Government And Agency Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	5	0
U.S. Government And Agency Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	139	172
U.S. Government And Agency Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
U.S. Government And Agency Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
U.S. Equity Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	308
U.S. Equity Securities [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	2,434
U.S. Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	86
U.S. Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	273
U.S. Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	222
U.S. Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	2,161
U.S. Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
U.S. Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Residential Real Estate [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	96	37
Residential Real Estate [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	810	587
Residential Real Estate [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	68	31
Residential Real Estate [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	525	522
Residential Real Estate [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Residential Real Estate [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Residential Real Estate [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	28	6
Residential Real Estate [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	285	65
Corporate Debt Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	805	682
Corporate Debt Securities [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	4,889	3,670
Corporate Debt Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	9	0
Corporate Debt Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	3	2
Corporate Debt Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	795	681
Corporate Debt Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	4,275	3,083
Corporate Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	1	1
Corporate Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	611	585
Non-U.S. Equity Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	187
Non-U.S. Equity Securities [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	1,494
Non-U.S. Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	79
Non-U.S. Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	131
Non-U.S. Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	108
Non-U.S. Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	1,363
Non-U.S. Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Non-U.S. Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Other Fixed Income [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	38	45
Other Fixed Income [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	576	689
Other Fixed Income [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	1
Other Fixed Income [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	1
Other Fixed Income [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	38	44
Other Fixed Income [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	576	688
Other Fixed Income [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Other Fixed Income [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Global Equity Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	515	19
Global Equity Securities [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	3,419	197
Global Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	118	0
Global Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	402	0
Global Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	397	19
Global Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	3,017	197
Global Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Global Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Absolute Return [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	49	47
Absolute Return [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	513	487
Absolute Return [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Absolute Return [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Absolute Return [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Absolute Return [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Absolute Return [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	49	47
Absolute Return [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	$ 513	$ 487

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Fair Value Measurements (Schedule Of Unrealized Gains Losses Related To Available-For-Sale Investments) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Schedule of Available-for-sale Securities [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value	$ 240		$ 188
Cash And Cash Equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	21		24
Total Fair Value	21	[1]	24	[1]
U.S. Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	331		334
Total Unrealized Gains	618		518
Total Unrealized Losses	0		(3)
Total Fair Value	949	[1]	849	[1]
Non-U.S. Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	199		194
Total Unrealized Gains	181		131
Total Unrealized Losses	(1)		(2)
Total Fair Value	379	[1]	323	[1]
U.S. Government And Agency Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	723		774
Total Unrealized Gains	97		102
Total Unrealized Losses	0		0
Total Fair Value	820	[1]	876	[1]
Municipal Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	56		56
Total Unrealized Gains	4		2
Total Unrealized Losses	(1)		0
Total Fair Value	59	[1]	58	[1]
Other Fixed-Income Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	168		96
Total Unrealized Gains	5		3
Total Unrealized Losses	0		0
Total Fair Value	173	[1]	99	[1]
Securities (Assets) [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	1,498		1,478
Total Unrealized Gains	905		756
Total Unrealized Losses	(2)		(5)
Total Fair Value	$ 2,401	[1]	$ 2,229	[1]

[1] Excludes $240 million and $188 million at December 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

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Derivatives And Hedging Activities (Outstanding Derivative Balances) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Total Commodity Risk [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	$ (329)	$ (720)
Netting	0	0
Cash Collateral	165	478
Total Derivative Balances	(164)	(242)
Other Current Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	48	54
Netting	(25)	(39)
Cash Collateral	36	103
Total Derivative Balances	59	118
Other Noncurrent Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	99	113
Netting	(11)	(59)
Cash Collateral	0	0
Total Derivative Balances	88	54
Other Current Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(255)	(489)
Netting	25	39
Cash Collateral	115	274
Total Derivative Balances	(115)	(176)
Other Noncurrent Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(221)	(398)
Netting	11	59
Cash Collateral	14	101
Total Derivative Balances	$ (196)	$ (238)

XML

Quarterly Consolidated Financial Data

12 Months Ended

Dec. 31, 2012

Quarterly Consolidated Financial Data

QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)

	Quarter ended
(in millions, except per share amounts)	December 31		September 30		June 30		March 31
2012
PG&E CORPORATION
Operating revenues	$	3,830	$	3,976	$	3,593	$	3,641
Operating income		125		614		467		487
Net income (loss)		(9)		364		239		236
Income (loss) available for common shareholders		(13)		361		235		233
Net earnings (loss) per common share, basic		(0.03)		0.84		0.56		0.56
Net earnings (loss) per common share, diluted		(0.03)		0.84		0.55		0.56
Common stock price per share:
High		43.48		46.51		45.20		43.72
Low		39.71		42.41		42.04		40.16
UTILITY
Operating revenues	$	3,829	$	3,974	$	3,592	$	3,640
Operating income		127		613		467		488
Net income		13		340		227		231
Income available for common stock		9		337		223		228
2011
PG&E CORPORATION
Operating revenues	$	3,815	$	3,860	$	3,684	$	3,597
Operating income		358		408		692		484
Net income		87		203		366		202
Income available for common shareholders		83		200		362		199
Net earnings per common share, basic		0.20		0.50		0.91		0.50
Net earnings per common share, diluted		0.20		0.50		0.91		0.50
Common stock price per share:
High		43.24		43.32		46.52		47.60
Low		36.86		39.21		41.39		42.47
UTILITY
Operating revenues	$	3,813	$	3,859	$	3,683	$	3,596
Operating income		359		402		699		484
Net income		89		196		359		201
Income available for common stock		85		193		355		198

During the fourth quarter 2012, the Utility recorded a charge to net income of $353 million for disallowed capital expenditures associated with the pipeline safety enhancement plan.  See Note 15 of the Notes to the Consolidated Financial Statements

During the second quarter 2012 the Utility recorded a provision of $80 million for estimated third-party claims related to the San Bruno accident.  During the first quarter 2012, second quarter of 2012, third quarter of 2012, and fourth quarter 2012, the Utility submitted insurance claims to certain insurers for the lower layers and recognized $11 million, $25 million, $99 million, and $50 million, respectively, for insurance recoveries.  See Note 15 of the Notes to the Consolidated Financial Statements.

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Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 5,088	$ 4,733
Cost Of Removal Obligation [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	3,625	3,460
Recoveries In Excess Of ARO [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	620	611
Public Purpose Programs [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	590	499
Other Long-Term Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	253	163
Total Long Term Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 5,088	$ 4,733

XML

Quarterly Consolidated Financial Data (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Consolidated Financial Data [Abstract]

Schedule Of Quarterly Consolidated Financial Data

	Quarter ended
(in millions, except per share amounts)	December 31		September 30		June 30		March 31
2012
PG&E CORPORATION
Operating revenues	$	3,830	$	3,976	$	3,593	$	3,641
Operating income		125		614		467		487
Net income (loss)		(9)		364		239		236
Income (loss) available for common shareholders		(13)		361		235		233
Net earnings (loss) per common share, basic		(0.03)		0.84		0.56		0.56
Net earnings (loss) per common share, diluted		(0.03)		0.84		0.55		0.56
Common stock price per share:
High		43.48		46.51		45.20		43.72
Low		39.71		42.41		42.04		40.16
UTILITY
Operating revenues	$	3,829	$	3,974	$	3,592	$	3,640
Operating income		127		613		467		488
Net income		13		340		227		231
Income available for common stock		9		337		223		228
2011
PG&E CORPORATION
Operating revenues	$	3,815	$	3,860	$	3,684	$	3,597
Operating income		358		408		692		484
Net income		87		203		366		202
Income available for common shareholders		83		200		362		199
Net earnings per common share, basic		0.20		0.50		0.91		0.50
Net earnings per common share, diluted		0.20		0.50		0.91		0.50
Common stock price per share:
High		43.24		43.32		46.52		47.60
Low		36.86		39.21		41.39		42.47
UTILITY
Operating revenues	$	3,813	$	3,859	$	3,683	$	3,596
Operating income		359		402		699		484
Net income		89		196		359		201
Income available for common stock		85		193		355		198

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Fair Value Measurements (Level 3 Reconciliation) (Details) (Fair Value, Inputs, Level 3 [Member], Price Risk Management Instruments [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Fair Value, Inputs, Level 3 [Member] | Price Risk Management Instruments [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Liability balance as of January 1	$ (74)		$ (399)
Realized and unrealized gains (losses): Included in regulatory assets and liabilities or balancing accounts	(5)	[1]	122	[1]
Transfers out of Level 3	0		203
Liability balance as of December 31	$ (79)		$ (74)

[1] Price risk management activity is recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.

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Commitments And Contingencies (Gas Supply, Transportation And Storage) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Long-term Purchase Commitment [Line Items]
2013	$ 3,094
2014	3,434
2015	3,414
2016	3,298
2017	3,140
Thereafter	36,518
Total	52,898
Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Cost of natural gas purchases	1,300	1,800	1,600
Natural Gas, Gas Transportation and Gas Storage Purchases [Member]
Long-term Purchase Commitment [Line Items]
2013	707
2014	208
2015	192
2016	152
2017	108
Thereafter	865
Total	$ 2,232

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Measurements [Abstract]

Assets And Liabilities Measured At Fair Value On A Recurring Basis

	Fair Value Measurements
	At  December 31, 2012
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	209	$	-	$	-	$	-	$	209
Nuclear decommissioning trusts
Money market investments		21		-		-		-		21
U.S. equity securities		940		9		-		-		949
Non-U.S. equity securities		379		-		-		-		379
U.S. government and agency securities		681		139		-		-		820
Municipal securities		-		59		-		-		59
Other fixed-income securities		-		173		-		-		173
Total nuclear decommissioning trusts (2)		2,021		380		-		-		2,401
Price risk management instruments
(Note 10)
Electricity		1		60		80		6		147
Gas		-		5		1		(6)		-
Total price risk management instruments		1		65		81		-		147
Rabbi trusts
Fixed-income securities		-		30		-		-		30
Life insurance contracts		-		72		-		-		72
Total rabbi trusts		-		102		-		-		102
Long-term disability trust
Money market investments		10		-		-		-		10
U.S. equity securities		-		14		-		-		14
Non-U.S. equity securities		-		11		-		-		11
Fixed-income securities		-		136		-		-		136
Total long-term disability trust		10		161		-		-		171
Total assets	$	2,241	$	708	$	81	$	-	$	3,030
Liabilities:
Price risk management instruments
(Note 10)
Electricity	$	155	$	144	$	160	$	(156)	$	303
Gas		8		9		-		(9)		8
Total liabilities	$	163	$	153	$	160	$	(165)	$	311

⁽¹⁾ Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

⁽²⁾ Excludes $240 million at December 31, 2012 primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2011
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	206	$	-	$	-	$	-	$	206
Nuclear decommissioning trusts
Money market investments		24		-		-		-		24
U.S. equity securities		841		8		-		-		849
Non-U.S. equity securities		323		-		-		-		323
U.S. government and agency securities		720		156		-		-		876
Municipal securities		-		58		-		-		58
Other fixed-income securities		-		99		-		-		99
Total nuclear decommissioning trusts (2)		1,908		321		-		-		2,229
Price risk management instruments
(Note 10)
Electricity		-		92		69		8		169
Gas		-		6		-		(3)		3
Total price risk management instruments		-		98		69		5		172
Rabbi trusts
Fixed-income securities		-		25		-		-		25
Life insurance contracts		-		67		-		-		67
Total rabbi trusts		-		92		-		-		92
Long-term disability trust
Money market investments		13		-		-		-		13
U.S. equity securities		-		15		-		-		15
Non-U.S. equity securities		-		9		-		-		9
Fixed-income securities		-		145		-		-		145
Total long-term disability trust		13		169		-		-		182
Total assets	$	2,127	$	680	$	69	$	5	$	2,881
Liabilities:
Price risk management instruments
(Note 10)
Electricity	$	411	$	289	$	143	$	(441)	$	402
Gas		31		13		-		(32)		12
Total liabilities	$	442	$	302	$	143	$	(473)	$	414

⁽¹⁾ Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

⁽²⁾ Excludes $188 million at December 31, 2011 primarily related to deferred taxes on appreciation of investment value.

Sensitivity Analysis

	Fair Value at
(in millions)	31-Dec-12
Fair Value Measurement	Assets		Liabilities		Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights	$	80	$	16	Market approach	CRR auction prices	$	(9.04) - 55.15
Power purchase agreements	$	-	$	145	Discounted cash flow	Forward prices	$	8.59 - 62.90

Level 3 Reconciliation

	Price Risk Management Instruments
(in millions)	2012		2011
Liability balance as of January 1	$	(74)	$	(399)
Realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)		(5)		122
Transfers out of Level 3		-		203
Liability balance as of December 31	$	(79)	$	(74)

 ⁽¹⁾ Price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and   purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets

Carrying Amount And Fair Value Of Financial Instruments

	At December 31,
	2012				2011
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation	$	349	$	371	$	349	$	380
Utility		11,645		13,946		10,545		12,543
Energy recovery bonds (Note 5)		-		-		423		433

Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments

				Total		Total
	Amortized			Unrealized		Unrealized		Total Fair
(in millions)	Cost			Gains		Losses		Value (1)
As of December, 2012
Money market investments	$	21	$	-	$	-	$	21
Equity securities
U.S.		331		618		-		949
Non-U.S.		199		181		(1)		379
Debt securities
U.S. government and agency
securities		723		97		-		820
Municipal securities		56		4		(1)		59
Other fixed-income securities		168		5		-		173
Total	$	1,498	$	905	$	(2)	$	2,401
As of December 31, 2011
Money market investments	$	24	$	-	$	-	$	24
Equity securities
U.S.		334		518		(3)		849
Non-U.S.		194		131		(2)		323
Debt securities
U.S. government and agency securities		774		102		-		876
Municipal securities		56		2		-		58
Other fixed-income securities		96		3		-		99
Total	$	1,478	$	756	$	(5)	$	2,229

 ⁽¹⁾ Excludes $240 million and $188 million at December 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

Schedule Of Long Term Debt Repayments

(in millions)	As of December 31, 2012
Less than 1 year	$	5
1-5 years		456
5-10 years		218
More than 10 years		373
Total maturities of debt securities	$	1,052

Schedule Of Activity For Debt And Equity Securities

	2012		2011		2010
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust
investments	$	1,133	$	1,928	$	1,405
Gross realized gains on sales of securities held as available-for-sale		19		43		42
Gross realized losses on sales of securities held as available-for-sale		(17)		(30)		(11)

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Debt (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012 days
Debt [Line Items]
Interest including LIBOR on credit facilities	Borrowings under the revolving credit facilities (other than swingline loans) bear interest based, at PG&E Corporation's and the Utility's election, on (1) a London Interbank Offered Rate ("LIBOR") plus an applicable margin or (2) the base rate plus an applicable margin. The base rate will equal the higher of the following: the administrative agent's announced base rate, 0.5% above the federal funds rate, or the one-month LIBOR plus an applicable margin. Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods.
Average yield on outstanding commercial paper	0.92%
Debt covenant ratio of total consolidated debt to total consolidated capitalization percentage	65.00%
Ownership requirement percentage	80.00%
Required ownership of voting capital stock	70.00%
Commercial paper program maximum	$ 1,750,000,000
Commercial paper, maturities (days)	365
Commercial paper average yield	0.36%
Interest including LIBOR on Floating Rate Senior Notes	For the years ended December 31, 2012 and 2011 the average interest rate on the Floating Rate Senior Notes was 0.92% and 0.94%, respectivley.
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	300,000,000	[1]
Right to increase commitments	100,000,000
Line of Credit Facility, Expiration Date	May 31, 2016
Utility [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	3,000,000,000	[2]
Right to increase commitments	500,000,000
Line of Credit Facility, Expiration Date	May 31, 2016
PG&E Corporation's [Member]
Debt [Line Items]
Average outstanding borrowings	21,000,000
Maximum outstanding balance	120,000,000
Commercial Paper [Member]
Debt [Line Items]
Average outstanding borrowings	665,000,000
Maximum outstanding balance	1,400,000,000
Credit Facilities [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	3,300,000,000
Floating Rate Senior Notes [Member]
Debt [Line Items]
Debt instrument, face amount	$ 250,000,000

[1] Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.

[2] Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days

XML

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Pacific Gas And Electric Company [Member]
Customer advances for construction	$ 101	$ 108
Reserve for damages	175	243
Environmental reserve	97	157
Compensation	229	310
Net operating loss carryforward	938	728
Other	264	217
Total deferred income tax assets	1,804	1,763
Regulatory balancing accounts	256	643
Property related basis differences	7,449	6,544
Income tax regulatory asset	663	588
Other	173	192
Total deferred income tax liabilities	8,541	7,967
Total net deferred income tax liabilities	6,737	6,204
Included in current liabilities (assets)	(11)	196
Included in noncurrent liabilities	6,748	6,008
Utility [Member]
Customer advances for construction	101	108
Reserve for damages	175	243
Environmental reserve	97	157
Compensation	179	258
Net operating loss carryforward	736	567
Other	255	180
Total deferred income tax assets	1,543	1,513
Regulatory balancing accounts	256	643
Property related basis differences	7,447	6,536
Income tax regulatory asset	663	588
Other	99	105
Total deferred income tax liabilities	8,465	7,872
Total net deferred income tax liabilities	6,922	6,359
Included in current liabilities (assets)	(17)	199
Included in noncurrent liabilities	$ 6,939	$ 6,160

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Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Statement Of Cash Flows) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Net income	$ 830		$ 858		$ 1,113
Deferred income taxes and tax credits, net	648		544		756
Net cash provided by operating activities	4,882		3,739		3,206
Other	104		(113)		(70)
Net cash provided by (used in) investing activities	(4,526)		(3,986)		(3,857)
Borrowings under revolving credit facilities	120		358		490
Repayments under revolving credit facilities	0		(358)		(490)
Proceeds from issuance of long-term debt, net of discount and issuance costs of $2 in 2009	1,137		792		1,327
Common stock issued	751		662		303
Common stock dividends paid	(746)		(704)		(662)
Other	14		41		(88)
Net cash (used) in financing activities	(468)		469		415
Net change in cash and cash equivalents	(112)		222		(236)
Cash and cash equivalents at January 1	513		291		527
Cash and cash equivalents at December 31	401		513		291
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs	13		8		23
Cash received (paid) for:
Interest, net of amounts capitalized	(594)		(647)		(627)
Income taxes, net	114		(42)		(135)
Noncash common stock issuances	(22)		(24)		(265)
Common stock dividends declared but not yet paid	(196)		(188)		(183)
PG&E Corporation [Member]
Net income	816		844		1,099
Depreciation and amortization	51		36		38
Equity in earnings of subsidiaries	(817)		(852)		(1,105)
Deferred income taxes and tax credits, net	(31)		(26)		19
Noncurrent income taxes receivable/payable	(6)		(47)		34
Current income taxes receivable/payable	(82)		49		(1)
Other	20		(80)		(50)
Net cash provided by operating activities	(49)		(76)		34
Investment in subsidiaries	(1,023)		(759)		(347)
Dividends received from subsidiaries	716	[1]	716	[1]	716	[1]
Proceeds from tax equity investments	228		129		7
Other	0		0		(4)
Net cash provided by (used in) investing activities	(79)		86		372
Borrowings under revolving credit facilities	120		150		90
Repayments under revolving credit facilities	0		(150)		(90)
Common stock issued	751		662		303
Common stock dividends paid	(746)	[2]	(704)	[2]	(662)	[2]
Other	1		1		0
Net cash (used) in financing activities	126		(41)		(359)
Net change in cash and cash equivalents	(2)		(31)		47
Cash and cash equivalents at January 1	209		240		193
Cash and cash equivalents at December 31	207		209		240
Cash received (paid) for:
Interest, net of amounts capitalized	(20)		(20)		(20)
Income taxes, net	(60)		8		36
Noncash common stock issuances	22		24		265
Common stock dividends declared but not yet paid	$ 196		$ 188		$ 183

[1] Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow.

[2] On January 15, April 15, July 15, October 15, 2012, PG&E Corporation paid quarterly common stock dividends of $0.455 per share. On January 15, April 15, July 15, October 15, 2011, PG&E Corporation paid a quarterly common stock dividend of $0.455 per share. 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

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Preferred Stock (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Preferred Stock [Line Items]
Preferred stock dividends	$ 14	$ 14	$ 14
$25 Par Value [Member] | Utility [Member]
Preferred Stock [Line Items]
Preferred stock, par value	$ 25
Preferred stock, shares issued	75,000,000
$100 Par Value [Member] | Utility [Member]
Preferred Stock [Line Items]
Preferred stock, par value	$ 100
Preferred stock, shares issued	10,000,000
$100 Par Value [Member] | PG&E Corporation [Member]
Preferred Stock [Line Items]
Preferred stock, par value	$ 100
Preferred stock, shares issued	5,000,000
No Par Value [Member] | PG&E Corporation [Member]
Preferred Stock [Line Items]
Preferred stock, shares authorized	80,000,000
Nonredeemable Preferred Stock [Member]
Preferred Stock [Line Items]
Preferred stock dividends per share, low range	$ 1.25
Preferred stock dividends per share, high range	$ 1.5
Nonredeemable Preferred Stock [Member] | $25 Par Value [Member]
Preferred Stock [Line Items]
Preferred stock, par value	$ 25
Preferred stock, shares authorized	5,784,825
Redeemable Preferred Stock [Member]
Preferred Stock [Line Items]
Preferred stock dividends per share, low range	$ 1.09
Preferred stock dividends per share, high range	$ 1.25
Redeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Preferred stock, shares issued	4,534,958,000,000

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Summary Of Significant Accounting Policies (Schedule Of Changes In Asset Retirement Obligations) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Summary Of Significant Accounting Policies [Abstract]
ARO liability at December 31	$ 1,609	$ 1,586
Revision in estimated cash flows	1,301	10
Accretion	101	100
Liabilities settled	(92)	(87)
ARO liability at December 31	$ 2,919	$ 1,609

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Consolidated Statements Of Equity (USD $) In Millions, except Share data	Total USD ($)	Pacific Gas And Electric Company [Member] USD ($)	Common Stock Shares [Member]	Preferred Stock [Member] Pacific Gas And Electric Company [Member] USD ($)	Common Stock Amount [Member] USD ($)	Common Stock Amount [Member] Pacific Gas And Electric Company [Member] USD ($)	Additional Paid-In Capital [Member] Pacific Gas And Electric Company [Member] USD ($)	Reinvested Earnings [Member] USD ($)	Reinvested Earnings [Member] Pacific Gas And Electric Company [Member] USD ($)	Accumulated Other Comprehensive Income (Loss) [Member] USD ($)	Accumulated Other Comprehensive Income (Loss) [Member] Pacific Gas And Electric Company [Member] USD ($)	Total Shareholders' Equity [Member] USD ($)	Total Shareholders' Equity [Member] Pacific Gas And Electric Company [Member] USD ($)	Noncontrolling Interest - Preferred Stock Of Subsidiary [Member] USD ($)
Balance at Dec. 31, 2009	$ 10,585			$ 258	$ 6,280	$ 1,322	$ 3,055	$ 4,213	$ 6,704	$ (160)	$ (154)	$ 10,333	$ 11,185	$ 252
Balance, in shares at Dec. 31, 2009			371,272,457
Net income	1,113	1,121						1,113	1,121			1,113	1,121
Other comprehensive income (loss)	(42)	(41)								(42)	(41)	(42)	(41)
Equity contribution		190					190						190
Common stock issued, net	568				568
Common stock issued, net, shares			23,954,748
Stock-based compensation amortization	34				34							34
Common stock dividends declared	(706)							(706)	(716)			(706)	(716)
Preferred stock dividend									(14)				(14)
Tax benefit from employee stock plans	(4)				(4)		(4)					(4)	(4)
Preferred stock dividend requirement of subsidiary	(14)							(14)				(14)
Balance at Dec. 31, 2010	11,534			258	6,878	1,322	3,241	4,606	7,095	(202)	(195)	11,282	11,721	252
Balance, in shares at Dec. 31, 2010			395,227,205
Net income	858	845						858	845			858	845
Other comprehensive income (loss)	(11)	(7)								(11)	(7)	(11)	(7)
Equity contribution		555					555						555
Common stock issued, net	686				686							686
Common stock issued, net, shares			17,029,877
Stock-based compensation amortization	37				37							37
Common stock dividends declared	(738)							(738)	(716)			(738)	(716)
Preferred stock dividend									(14)				(14)
Tax benefit from employee stock plans	1				1							1
Preferred stock dividend requirement of subsidiary	(14)							(14)				(14)
Balance at Dec. 31, 2011	12,353			258	7,602	1,322	3,796	4,712	7,210	(213)	(202)	12,101	12,384	252
Balance, in shares at Dec. 31, 2011	412,257,082	264,374,809	412,257,082
Net income	830	811						830				830	811
Other comprehensive income (loss)	112	109								112	109	112	109
Equity contribution		885					885						885
Common stock issued, net	773				773							773
Common stock issued, net, shares			18,461,211
Stock-based compensation amortization	52				52							52
Common stock dividends declared	(781)	(716)						(781)				(781)	(716)
Preferred stock dividend		(14)											(14)
Tax benefit from employee stock plans	1				1		1					1	1
Preferred stock dividend requirement of subsidiary	(14)							(14)				(14)
Balance at Dec. 31, 2012	$ 13,326			$ 258	$ 8,428	$ 1,322	$ 4,682	$ 4,747	$ 7,291	$ (101)	$ (93)	$ 13,074	$ 13,460	$ 252
Balance, in shares at Dec. 31, 2012	430,718,293	264,374,809	430,718,293

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Preferred Stock (Summary Of Issued And Outstanding Preferred Stock) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Preferred Stock [Line Items]
Total Preferred Stock	$ 0	$ 0
Utility [Member]
Preferred Stock [Line Items]
Total Preferred Stock	258
Nonredeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Nonredeemable preferred stock, value	145
Redeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Total Preferred Stock	4,534,958
Redeemable preferred stock, value	113
5.00% Series [Member] | Nonredeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Total Preferred Stock	400,000
Nonredeemable preferred stock, value	10
5.50% Series [Member] | Nonredeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Total Preferred Stock	1,173,163
Nonredeemable preferred stock, value	30
6.00% Series [Member] | Nonredeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Total Preferred Stock	4,211,662
Nonredeemable preferred stock, value	105
4.36% Series [Member] | Redeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Total Preferred Stock	418,291
Redemption Price	$ 25.75
Redeemable preferred stock, value	11
4.50% Series [Member] | Redeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Total Preferred Stock	611,142
Redemption Price	$ 26
Redeemable preferred stock, value	15
4.80% Series [Member] | Redeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Total Preferred Stock	793,031
Redemption Price	$ 27.25
Redeemable preferred stock, value	20
5.00% Series [Member] | Redeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Total Preferred Stock	1,778,172
Redemption Price	$ 26.75
Redeemable preferred stock, value	44
5.00% Series A [Member] | Redeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Total Preferred Stock	934,322
Redemption Price	$ 26.75
Redeemable preferred stock, value	$ 23

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Schedule I - Condensed Financial Information Of Parent (Tables)

12 Months Ended

Dec. 31, 2012

Schedule I - Condensed Financial Information Of Parent [Abstract]

Schedule of Condensed Statements of Income

	Year Ended December 31,
	2012	2011	2010
Administrative service revenue	$ 43	$ 44	$ 53
Operating expenses	(41	)	(55	)
Interest income	1	1	1
Interest expense	(22	)	(35	)
Other income (expense)	(39	)	4
Equity in earnings of subsidiaries	817	852	1,105
Income before income taxes	759	814	1,073
Income tax benefit	57	30	26
Net Income	816	$ 844	$ 1,099
Other Comprehensive Income
Pension and other postretirement benefit plans (net of income tax of $72, $9, $25 in 2012, 2011, and 2010, respectively)	108	(11	)
Other (net of income tax of $3 in 2012)	4	-	-
Total other comprehensive income (loss)	112	(11	)
Comprehensive Income	$ 928	$ 833	$ 1,057
Weighted average common shares outstanding, basic	424	401	382
Weighted average common shares outstanding, diluted	425	402	392
Net earnings per common share, basic	$ 1.92	$ 2.10	$ 2.86
Net earnings per common share, diluted	$ 1.92	$ 2.10	$ 2.82

Schedule of Condensed Balance Sheet

	Balance at December 31,
	2012	2011
ASSETS
Current Assets
Cash and cash equivalents	$ 207	$ 209
Advances to affiliates	26	18
Income taxes receivable	33	8
Deferred income taxes	-	4
Total current assets	266	239
Noncurrent Assets
Equipment	1	14
Accumulated depreciation	(1	)
Net equipment	-	-
Investments in subsidiaries	13,387	12,378
Other investments	102	94
Income taxes receivable	5	2
Deferred income taxes	178	143
Other	1	2
Total noncurrent assets	13,673	12,619
Total Assets	$ 13,939	$ 12,858
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$ 120	$ -
Accounts payable - other	48	21
Income taxes payable	-	57
Other	221	208
Total current liabilities	389	286
Noncurrent Liabilities
Longdebt	349	349
Other	127	122
Total noncurrent liabilities	476	471
Common Shareholders' Equity
Common stock	8,428	7,602
Reinvested earnings	4,747	4,712
Accumulated other comprehensive loss	(101	)
Total common shareholders' equity	13,074	12,101
Total Liabilities and Shareholders' Equity	$ 13,939	$ 12,858

Schedule Of Condensed Statement Of Cash Flows

		Year Ended December 31,
		2012			2011			2010
Cash Flows from Operating Activities:
Net income		$	816		$	844		$	1,099
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization			51			36			38
Equity in earnings of subsidiaries			(817	)		(852	)		(1,105	)
Deferred income taxes and tax credits, net			(31	)		(26	)		19
Noncurrent income taxes receivable/payable			(6	)		(47	)		34
Current income taxes receivable/payable			(82	)		49			(1	)
Other			20			(80	)		(50	)
Net cash provided by (used in) operating activities			(49)			(76	)		34
Cash Flows From Investing Activities:
Investment in subsidiaries			(1,023	)		(759	)		(347	)
Dividends received from subsidiaries (1)			716			716			716
Proceeds from tax equity investments			228			129			7
Other			-			-			(4	)
Net cash provided by (used in) investing activities			(79)			86			372
Cash Flows From Financing Activities:
Borrowings under revolving credit facilities			120			150			90
Repayments under revolving credit facilities			-			(150	)		(90	)
Common stock issued			751			662			303
Common stock dividends paid (2)			(746	)		(704	)		(662	)
Other			1			1			-
Net cash provided by (used in) financing activities			126			(41	)		(359	)
Net change in cash and cash equivalents			(2	)		(31	)		47
Cash and cash equivalents at January 1			209			240			193
Cash and cash equivalents at December 31		$	207		$	209		$	240
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized		$	(20	)	$	(20	)	$	(20	)
Income taxes, net			(60	)		8			36
Supplemental disclosures of noncash investing and financing
activities
Noncash common stock issuances		$	22		$	24		$	265
Common stock dividends declared but not yet paid			196			188			183
(1	)
(2	)
	On January 15, April 15, July 15, October 15, 2011, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
	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.

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Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Summary Of Significant Accounting Policies [Abstract]

Schedule Of Estimated Useful Lives And Balances Of Utility's Property, Plant And Equipment

	Estimated Useful	Balance at December 31,
(in millions, except estimated useful lives)	Lives (years)	2012		2011
Electricity generating facilities (1)	10 to 100	$	8,253	$	6,488
Electricity distribution facilities	10 to 55		23,767		22,395
Electricity transmission	10 to 70		7,681		6,968
Natural gas distribution facilities	20 to 53		8,257		7,832
Natural gas transportation and storage	5 to 48		4,314		4,099
Construction work in progress			1,894		1,770
Total property, plant, and equipment			54,166		49,552
Accumulated depreciation			(16,643)		(15,898)
Net property, plant, and equipment		$	37,523	$	33,654

 ⁽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.)

Schedule Of Changes In Asset Retirement Obligations

(in millions)
ARO liability at December 31, 2010	$	1,586
Revision in estimated cash flows		10
Accretion		100
Liabilities settled		(87)
ARO liability at December 31, 2011		1,609
Revision in estimated cash flows		1,301
Accretion		101
Liabilities settled		(92)
ARO liability at December 31, 2012	$	2,919

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Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2012

Summary Of Significant Accounting Policies [Abstract]

Cash And Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.  

Restricted Cash

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.)  

Allowance For Doubtful Accounts Receivable

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

Inventories are carried at weighted-average cost.  Inventories include natural gas stored underground and materials and supplies.  Natural gas stored underground represents purchases that are recorded to inventory and then expensed at weighted average cost when withdrawn and distributed to customers or used in electric generation.  Materials and supplies are recorded to inventory when purchased and then expensed or capitalized to plant, as appropriate, when consumed or installed.

Property, Plant, And Equipment

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 estimated useful lives and balances of its property, plant, and equipment were as follows:

	Estimated Useful	Balance at December 31,
(in millions, except estimated useful lives)	Lives (years)	2012		2011
Electricity generating facilities (1)	10 to 100	$	8,253	$	6,488
Electricity distribution facilities	10 to 55		23,767		22,395
Electricity transmission	10 to 70		7,681		6,968
Natural gas distribution facilities	20 to 53		8,257		7,832
Natural gas transportation and storage	5 to 48		4,314		4,099
Construction work in progress			1,894		1,770
Total property, plant, and equipment			54,166		49,552
Accumulated depreciation			(16,643)		(15,898)
Net property, plant, and equipment		$	37,523	$	33,654

 ⁽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.)

Depreciation

Depreciation 

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment in a particular class of property.  This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment.  The Utility's composite depreciation rates were 3.63% in 2012, 3.67% in 2011, and 3.38% in 2010.

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 against 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.

AFUDC

AFUDC

AFUDC is a method used to compensate the Utility for the estimated cost of debt (i.e., interest) and equity funds used to finance regulated plant additions and is capitalized as part of the cost of construction.  AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service.  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 $49 million and $107 million during 2012, $40 million and $87 million during 2011, and $50 million and $110 million during 2010, related to debt and equity, respectively.

Regulation And Regulated Operations

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 regulatory assets, 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 in which 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's ability to recover the revenue requirements that have been authorized by the CPUC in a general rate case (“GRC”) and a gas transmission and storage rate case (“GT&S”) does not depend on the volume of the Utility's sales of electricity and natural gas services. The Utility's recovery of a significant portion of its authorized revenue requirements through rates is independent, or “decoupled,” from the volume of electricity and natural gas sales.  

The Utility records differences between actual customer billings and the Utility's authorized revenue requirement, as well as differences between incurred costs and customer billings or authorized revenue meant to recover those costs.  To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account asset or liability, respectively and the differences do not have an impact on net income.  For further discussion, 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

Intangible assets primarily consist of hydroelectric facility licenses with terms ranging from 19 to 53 years.  The gross carrying amount of intangible assets was $110 million at December 31, 2012 and $112 million at December 31, 2011.  The accumulated amortization was $49 million at December 31, 2012 and $47 million at December 31, 2011.

The Utility's amortization expense related to intangible assets was $2 million in 2012, $3 million in 2011, and $4 million in 2010.  The estimated annual amortization expense for 2013 through 2017 based on the December 31, 2012 intangible assets balance is $3 million.  Intangible assets are recorded to other noncurrent assets - other in the Consolidated Balance Sheets.

Asset Retirement Obligations

Asset Retirement Obligations

PG&E Corporation and the Utility record an ARO at discounted fair value in the period in which the obligation is incurred if the discounted 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 ARO is accreted to its present value.  PG&E Corporation and the Utility also record an ARO if a legal obligation to perform an asset removal exists and can be reasonably estimated, but performance is conditional upon a future event.  The Utility recognizes timing differences between the recognition of costs and the costs recovered through the ratemaking process as regulatory assets or liabilities.  (See Note 3 below.)  The Utility has an ARO primarily for its nuclear generation facilities, certain fossil fuel-fired generation facilities, and gas transmission system assets.  

Detailed studies of the cost to decommission the Utility's nuclear generation facilities are conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceedings (“NDCTP”) conducted by the CPUC.  In December 2012, the Utility submitted its updated decommissioning cost estimate with the CPUC.  The estimated undiscounted cost to decommission the Utility's nuclear power plants increased by $1.4 billion due to higher spent nuclear fuel disposal costs and an increase in the scope of work.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear generation facilities.  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.  The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.  A significant portion of the increase in decommissioning cost estimates is due to the need to develop on-site storage for spent nuclear fuel because the federal government has failed to meet its obligation to develop a permanent repository for the disposal of nuclear waste from nuclear facilities in the United States.  The Utility expects that it will recover its future on-site storage costs from the federal government.  The Utility already has recovered $266 million for spent nuclear fuel costs incurred through 2010. (See “Spent Nuclear Fuel Storage Proceedings” in Note 15 below).  Recovered amounts will be refunded to customers through rates.  In its 2012 NDCTP application, the Utility requested that the CPUC issue a final decision by the end of 2013.

The estimated undiscounted nuclear decommissioning cost for the Utility's nuclear generation facilities was approximately $3.5 billion at December 31, 2012 and $2.3 billion at December 31, 2011, as filed in the 2012 and 2009 NDCTPs, respectively.  In future dollars, the estimated nuclear decommissioning cost is approximately $6.1 billion and $4.4 billion, respectively.  These estimates are based on the 2012 and 2009 decommissioning cost studies, respectively, and are prepared in accordance with CPUC requirements.  The estimated nuclear decommissioning cost in future dollars is discounted for GAAP purposes and recognized as an ARO on the Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued in accordance with GAAP was $2.5 billion at December 31, 2012 and $1.2 billion at December 31, 2011.  

A reconciliation of the changes in the ARO liability is as follows:

(in millions)
ARO liability at December 31, 2010	$	1,586
Revision in estimated cash flows		10
Accretion		100
Liabilities settled		(87)
ARO liability at December 31, 2011		1,609
Revision in estimated cash flows		1,301
Accretion		101
Liabilities settled		(92)
ARO liability at December 31, 2012	$	2,919

The Utility has identified the following AROs for which a reasonable estimate of fair value could not be made.  As a result, the Utility has not recorded a liability related to these AROs:  

∙      Restoration of land to its pre-use condition under the terms of certain land rights agreements.  Land rights will be maintained for the foreseeable future, and therefore, the Utility cannot reasonably estimate the settlement date(s) or range of settlement dates for the obligations associated with these assets;  

Removal and proper disposal of lead-based paint contained in some Utility facilities.  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 obligations; and

Removal of certain communications equipment from leased property, and retirement activities associated with substation and certain hydroelectric facilities.  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, expected to be economically beneficial.  Therefore, the settlement date(s) cannot be reasonably estimated at this time.

Disallowance of Plant Costs

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge to net income when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.  During 2012, the Utility recorded a $353 million charge to net income for capital expenditures incurred in connection with its pipeline safety enhancement plan that were either specifically disallowed or that are forecasted to exceed the CPUC's authorized levels.  (See “CPUC Gas Safety Rulemaking Proceeding” in Note 15 below).  No material disallowance losses were recorded in 2011 and $36 million in disallowance losses were recorded in 2010.

Gains And Losses On Debt Extinguishments

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 $163 million and $186 million at December 31, 2012 and 2011, respectively.  The amortization expense related to this loss was $23 million in 2012, $18 million in 2011, and $23 million in 2010.  Deferred gains and losses on debt extinguishments are recorded to current assets - regulatory assets and other noncurrent assets - regulatory assets in the Consolidated Balance Sheets.

Revenue Recognition

Revenue Recognition

The Utility recognizes revenues as electricity and natural gas services are delivered, and includes amounts for services rendered but not yet billed at the end of the period.  

The CPUC authorizes most of the Utility's revenue requirements in its GRC and its GT&S, which generally occur every three years.  The Utility's ability to recover revenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility's sales of electricity and natural gas services.  The Utility recognizes revenues once they have been authorized for rate recovery, amounts are objectively determinable and probable of recovery, and amounts will be collected within 24 months.  Generally, the revenue recognition criteria are met ratably over the year.  (See Note 3 below.)

The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose, demand response, and customer energy efficiency programs.  Generally, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred.

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.

The Utility's revenues and net income also are affected by incentive ratemaking mechanisms that adjust rates depending on the extent to which the Utility meets certain performance criteria.  

Income Taxes

Income Taxes

PG&E Corporation and the Utility use the liability method of accounting for income taxes.  Income tax provision includes current and deferred income taxes resulting from operations during the year.  PG&E Corporation and the Utility estimate current period actual tax expense in addition to calculating deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as depreciation, and are reported within the PG&E Corporation and Utility's balance sheets.  (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.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit.  

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

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

Nuclear Decommissioning Trusts

The Utility's nuclear generation facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.  

The Utility classifies its investments held in the nuclear decommissioning trusts as “available-for-sale.”  Since 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 its 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 through rates.  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

Accounting for Derivatives

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 probable of future recovery through regulated rates, are deferred and recorded in regulatory accounts.  

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 which qualify for the normal purchase and sales exception are not reflected in the Consolidated Balance Sheets at fair value, but are accounted for under the accrual method of accounting.  Therefore, expenses are recognized as incurred.

PG&E Corporation and the Utility offset 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 and the intention to offset exist.  (See Note 10 below.)

Fair Value Measurements

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.)

Variable Interest Entities

Variable Interest Entities

PG&E Corporation and the Utility are required to consolidate the financial results of any entities that they control.  In most cases, control can be determined based on majority ownership or voting interests.  However, there are certain entities known as variable interest entities (“VIEs”) for which control is difficult to discern based on ownership or voting interests alone.  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 in a VIE if it has the obligation to absorb expected losses or the right to receive expected gains that could potentially be significant to the VIE and if it has any decision-making rights associated with the activities that are most significant to the VIE's economic performance, including the power to design the VIE.  An enterprise that has a controlling financial interest in a VIE is known as the VIE's primary beneficiary and is required to consolidate the VIE.

In determining whether consolidation of a particular entity is required, PG&E Corporation and the Utility first evaluate whether the entity is a VIE.  If the entity is a VIE, PG&E Corporation and the Utility use a qualitative approach to determine if either is the primary beneficiary of the VIE.

Some of the counterparties to the Utility's power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility subject to the terms of a power purchase agreement.  In determining whether the Utility is the primary beneficiary of any of these VIEs, it assesses whether it absorbs any of the VIE's expected losses or receives any portion of the VIE's expected residual returns under the terms of the power purchase agreement.  This assessment includes an evaluation of how the risks and rewards associated with the power plant's activities are absorbed by variable interest holders, as well as an analysis of the variability in the VIE's gross margin and the impact of the power purchase agreement on the gross margin.  Under each of these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE.  The Utility does 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 any decision-making rights associated with the design of any VIEs, nor does the Utility have the power to direct the activities that are most significant to the economic performance of any VIEs such as dispatch rights, operating and maintenance activities, or re-marketing activities of the power plant after the termination of any VIE's power purchase agreement with the Utility.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2012, it did not consolidate any of them.

The Utility continued to consolidate the financial results of PG&E Energy Recovery Funding LLC (“PERF”), a VIE, at December 31, 2012, since the Utility is the primary beneficiary of PERF.  PERF was formed in 2005 as a wholly owned subsidiary of the Utility to issue energy recovery bonds (“ERBs”) in connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility's proceeding under Chapter 11 (“Chapter 11 Settlement Agreement”).  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.  PERF is expected to be dissolved in 2013.  (See Note 5 below.)  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 of PG&E Corporation, and the recovery property is not legally an asset of the Utility or PG&E Corporation.

At December 31, 2012, PG&E Corporation affiliates had entered into four tax equity agreements to fund residential and commercial retail solar energy installations with two privately held companies that are considered VIEs.  Under these agreements, PG&E Corporation has agreed to provide lease payments and investment contributions of up to $396 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies.  The majority of these amounts are recorded in other noncurrent assets - other in PG&E Corporation's Consolidated Balance Sheets.  At December 31, 2012, PG&E Corporation had made total payments of $361 million under these agreements and received $228 million in benefits and customer payments.  In determining whether  PG&E Corporation is the primary beneficiary of any of these VIEs, PG&E Corporation assesses which of the variable interest holders has control over these companies' significant economic activities, such as the design of the companies, vendor selection, construction, customer selection, and re-marketing activities after the termination of customer leases. PG&E Corporation determined that these companies control these activities, while its financial exposure from these agreements is generally limited to its lease payments and investment contributions to these companies.  Since PG&E Corporation was not the primary beneficiary of any of these VIEs at December 31, 2012, it did not consolidate any of them

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Commitments And Contingencies (Underground Electric Facilities, CPUC) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Commitments And Contingencies [Abstract]
Underground electric, conversion costs committed	$ 277
Underground electric, conversion costs expected	$ 86

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Energy Recovery Bonds (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Energy Recovery Bonds [Line Items]
Energy recovery bond, principal outstanding		$ 423
Debt instrument, maturity year	2012
First Series Of Energy Recovery Bonds [Member]
Energy Recovery Bonds [Line Items]
Debt instrument, issuance date	Feb. 10, 2005
Energy recovery bond, principal outstanding	1,900
Maturity date range, start	Sep. 25, 2006
Debt Instrument, Maturity Date Range, End	Dec. 25, 2012
Second Series Energy Recovery Bonds [Member]
Energy Recovery Bonds [Line Items]
Debt instrument, issuance date	Nov. 09, 2005
Energy recovery bond, principal outstanding	$ 844
Maturity date range, start	Jun. 25, 2009
Debt Instrument, Maturity Date Range, End	Dec. 25, 2012

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Schedule II - Consolidated Valuation And Qualifying Accounts (Tables)

12 Months Ended

Dec. 31, 2012

Schedule II - Consolidated Valuation And Qualifying Accounts [Abstract]

Schedule II - Consolidated Valuation And Qualifying Accounts

		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:
2012:
Allowance for uncollectible accounts(1)	$ 81	$ 66	$ -	$ 60	$ 87
2011:
Allowance for uncollectible accounts(1)	$ 81	$ 60	$ -	$ 60	$ 81
2010:
Allowance for uncollectible accounts(1)	$ 68	$ 56	$ -	$ 43	$ 81
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

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Regulatory Assets, Liabilities, And Balancing Accounts (Tables)

12 Months Ended

Dec. 31, 2012

Regulatory Assets, Liabilities, And Balancing Accounts [Abstract]

Long-Term Regulatory Assets

	Balance at December 31,
(in millions)	2012		2011
Pension benefits	$	3,275	$	2,899
Deferred income taxes		1,627		1,444
Utility retained generation		552		613
Environmental compliance costs		604		520
Price risk management		210		339
Electromechanical meters		194		247
Unamortized loss, net of gain, on reacquired debt		141		163
Other		206		281
Total long-term regulatory assets	$	6,809	$	6,506

Long-Term Regulatory Liabilities

	Balance at December 31,
(in millions)	2012		2011
Cost of removal obligations	$	3,625	$	3,460
Recoveries in excess of AROs		620		611
Public purpose programs		590		499
Other		253		163
Total long-term regulatory liabilities	$	5,088	$	4,733

Current Regulatory Balancing Accounts, Net

	Receivable (Payable)
	Balance at December 31,
(in millions)	2012		2011
Distribution revenue adjustment mechanism	$	219	$	223
Utility generation		117		241
Hazardous substance		56		57
Public purpose programs		(83)		97
Gas fixed cost		44		16
Energy recovery bonds		(43)		(105)
Energy procurement		77		(48)
Department of Energy Settlement		(250)		-
Other		165		227
Total regulatory balancing accounts, net	$	302	$	708

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Debt (Tables)

12 Months Ended

Dec. 31, 2012

Debt [Abstract]

Schedule Of Long-Term Debt

	December 31,
(in millions)	2012		2011
PG&E Corporation
Senior notes, 5.75%, due 2014		350		350
Unamortized discount		-		(1)
Total senior notes		350		349
Total PG&E Corporation long-term debt		350		349
Utility
Senior notes:
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		800
4.25% due 2021		300		300
3.25% due 2021		250		250
2.45% due 2022		400		-
6.05% due 2034		3,000		3,000
5.80% due 2037		950		950
6.35% due 2038		400		400
6.25% due 2039		550		550
5.40% due 2040		800		800
4.50% due 2041		250		250
4.45% due 2042		400		-
3.75% due 2042		350		-
Less: current portion		(400)		-
Unamortized discount, net of premium		(51)		(51)
Total senior notes, net of current portion		10,899		10,149
Pollution control bonds:
Series 1996 C, E, F, 1997 B, variable rates (1), due 2026 (2)		614		614
Series 2004 A-D, 4.75%, due 2023 (3)		345		345
Series 2009 A-D, variable rates (4), due 2016 and 2026 (5)		309		309
Series 2010 E, 2.25%, due 2026 (6)		-		50
Less: current portion		-		(50)
Total pollution control bonds		1,268		1,268
Total Utility long-term debt, net of current portion		12,167		11,417
Total consolidated long-term debt, net of current portion	$	12,517	$	11,766

 ⁽¹⁾  At December 31, 2012, interest rates on these bonds and the related loans ranged from 0.10% to 0.14%.

⁽²⁾  Each series of these bonds is supported by a separate letter of credit that expires on May 31, 2016. 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 consent from the issuer to the continuation of the series without a credit facility.

⁽³⁾ The Utility has obtained credit support from an insurance company for these bonds.

⁽⁴⁾ At December 31, 2012, interest rates on these bonds and the related loans ranged from 0.05% to 0.11%.

⁽⁵⁾ Each series of these bonds is supported by a separate direct-pay letter of credit that expires on May 31, 2016.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.

⁽⁶⁾ These bonds bore interest at 2.25% per year through April 1, 2012; and were subject to mandatory tender on April 2, 2012.  The Utility repurchased these bonds on April 2, 2012 and continues to hold them.

Schedule Of Long-Term Debt Repayments

(in millions,
except interest rates)	2013			2014				2015			2016				2017			Thereafter				Total
PG&E Corporation
Average fixed interest rate		-				5.75	%			-			-			-				-				5.75	%
Fixed rate obligations	$	-			$	350			$	-		$	-		$	-			$	-			$	350
Utility
Average fixed interest rate		6.25	%			4.80	%			-			-			5.63	%			5.45	%			5.43	%
Fixed rate obligations	$	400			$	1,000			$	-		$	-		$	700			$	9,595			$	11,695
Variable interest rate
as of December 31, 2012		-				-				-			0.11	%		-				-				0.11	%
Variable rate obligations	$	-			$	-			$	-		$	923	(1	)	-			$	-			$	923
Total consolidated debt	$	400			$	1,350			$	-		$	923		$	700			$	9,595			$	12,968

 ⁽¹⁾ These bonds, due in 2016 and 2026, are backed by letters of credit that expire on May 31, 2016.

Schedule Of Line Of Credit

						Letters of
	Termination	Facility				Credit				Commercial				Facility
(in millions)	Date	Limit				Outstanding		Borrowings		Paper				Availability
PG&E Corporation	May 2016	$	300	(1	)	$	-	$	120	$	-			$	180
Utility	May 2016		3,000	(2	)		266		-		370	(3	)		2,364	(3	)
Total revolving credit facilities		$	3,300			$	266	$	120	$	370			$	2,544

 ⁽¹⁾ Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.

⁽²⁾ Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.

⁽³⁾ The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.

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Consolidated Statements Of Cash Flows (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash Flows from Financing Activities
Net issuances of commercial paper, discount	$ 3	$ 4	$ 3
Proceeds from issuance of short-term debt, issuance costs	0	0	1
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs	13	8	23
Pacific Gas And Electric Company [Member]
Cash Flows from Financing Activities
Net issuances of commercial paper, discount	3	4	3
Proceeds from issuance of short-term debt, issuance costs	0	0	1
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs	$ 13	$ 8	$ 23

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Common Stock And Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2012

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule Of Compensation Expense For Share-Based Incentive Awards

(in millions)	2012		2011		2010
Restricted stock units	$	31	$	22	$	9
Other share-based compensation		-		1		14
Performance shares:
Equity awards		26		16		11
Liability awards		-		(13)		22
Total compensation expense (pre-tax)	$	57	$	26	$	56
Total compensation expense (after-tax)	$	34	$	16	$	33

Schedule Of Restricted Stock Units Activity

	Number of	Weighted Average Grant-
	Restricted Stock Units	Date Fair Value
Nonvested at January 1	1,626,048	$	42.57
Granted	923,001	$	42.17
Vested	(424,034)	$	41.88
Forfeited	(55,724)	$	42.64
Nonvested at December 31	2,069,291	$	42.52

Schedule Of Nonvested Performance-Based Units Activity

	Number of	Weighted Average Grant-
	Performance Shares	Date Fair Value
Nonvested at January 1	1,325,406	$	34.64
Granted	834,420	$	41.93
Vested	(425)	$	34.86
Forfeited (1)	(661,928)	$	35.71
Nonvested at December 31	1,497,473	$	38.15
(1) Includes performance shares that expired with zero value as performance targets were not met.

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Employee Benefit Plans (Estimated Amortized Net Periodic Benefit For 2012) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Unrecognized prior service cost	$ 24
Unrecognized net loss	6
Total	30
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Unrecognized prior service cost	20
Unrecognized net loss	110
Total	$ 130

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Related Party Agreements And Transactions (Tables)

12 Months Ended

Dec. 31, 2012

Related Party Agreements And Transactions [Abstract]

Schedule Of Significant Related Party Transactions

	Year Ended December 31,
(in millions)	2012		2011		2010
Utility revenues from:
Administrative services provided to PG&E Corporation	$	7	$	6	$	7
Utility expenses from:
Administrative services received from PG&E
Corporation	$	50	$	49	$	55
Utility employee benefit due to PG&E Corporation		51		33		27

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Debt (Schedule Of Long-Term Debt) (Details) (USD $) In Millions, unless otherwise specified																																									12 Months Ended									12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Pacific Gas And Electric Company [Member]	Dec. 31, 2011 Pacific Gas And Electric Company [Member]	Dec. 31, 2012 Utility [Member]	Dec. 31, 2011 Utility [Member]	Dec. 31, 2012 Senior Notes, 5.75%, Due 2014 [Member] Pacific Gas And Electric Company [Member]	Dec. 31, 2011 Senior Notes, 5.75%, Due 2014 [Member] Pacific Gas And Electric Company [Member]	Dec. 31, 2012 Senior Notes, 6.25% Due 2013 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 6.25% Due 2013 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 4.80% Due 2014 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 4.80% Due 2014 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 5.625% Due 2017 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 5.625% Due 2017 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 8.25% Due 2018 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 8.25% Due 2018 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 3.50% Due 2020 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 3.50% Due 2020 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 4.25% Due 2021[Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 4.25% Due 2021[Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 3.25% Due 2021 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 3.25% Due 2021 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 2.45% Due 2022 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 2.45% Due 2022 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 6.05% Due 2034 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 6.05% Due 2034 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 5.80% Due 2037 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 5.80% Due 2037 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 6.35% Due 2038 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 6.35% Due 2038 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 6.25% Due 2039 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 6.25% Due 2039 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 5.40% Due 2040 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 5.40% Due 2040 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 4.50% Due 2041 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 4.50% Due 2041 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 4.45% Due 2042 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 4.45% Due 2042 [Member] Utility [Member]	Dec. 31, 2012 Senior Notes, 3.75% Due 2042 [Member] Utility [Member]	Dec. 31, 2011 Senior Notes, 3.75% Due 2042 [Member] Utility [Member]	Dec. 31, 2012 Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 [Member]	Dec. 31, 2012 Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 [Member] Utility [Member]		Dec. 31, 2011 Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 [Member] Utility [Member]		Dec. 31, 2012 Pollution Control Bonds, Series 2004 A-D, 4.75%, Due 2023 [Member] Utility [Member]		Dec. 31, 2011 Pollution Control Bonds, Series 2004 A-D, 4.75%, Due 2023 [Member] Utility [Member]		Dec. 31, 2012 Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member]	Dec. 31, 2012 Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member] Utility [Member]		Dec. 31, 2011 Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member] Utility [Member]		Dec. 31, 2012 Pollution Control Bonds, Series 2010 E, 2.25%, Due 2026 (6) [Member] Utility [Member]		Dec. 31, 2011 Pollution Control Bonds, Series 2010 E, 2.25%, Due 2026 (6) [Member] Utility [Member]
Debt [Line Items]
Senior notes			$ 350	$ 349			$ 350	$ 350	$ 400	$ 400	$ 1,000	$ 1,000	$ 700	$ 700	$ 800	$ 800	$ 800	$ 800	$ 300	$ 300	$ 250	$ 250	$ 400	$ 0	$ 3,000	$ 3,000	$ 950	$ 950	$ 400	$ 400	$ 550	$ 550	$ 800	$ 800	$ 250	$ 250	$ 400	$ 0	$ 350	$ 0
Unamortized discount			0	(1)
Less: current portion					(400)	0
Unamortized discount, net of premium					(51)	(51)
Total senior notes, net of current portion					10,899	10,149
Pollution control bonds																																										614	[1],[2]	614	[1],[2]	345	[3]	345	[3]		309	[4],[5]	309	[4],[5]	0	[6]	50	[6]
Less: current portion					0	(50)
Total pollution control bonds					1,268	1,268
Total long-term debt, net of current portion	$ 12,517	$ 11,766	$ 12,167	$ 11,417	$ 12,517	$ 11,766
Interest rate on bonds, minimum																																									0.10%									0.05%
Interest rate on bonds, maximum																																									0.14%									0.11%

[1] At December 31, 2012, interest rates on these bonds and the related loans ranged from 0.10% to 0.14%.

[2] Each series of these bonds is supported by a separate letter of credit that expires on May 31, 2016. 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 consent from the issuer to the continuation of the series without a credit facility.

[3] The Utility has obtained credit support from an insurance company for these bonds.

[4] At December 31, 2012, interest rates on these bonds and the related loans ranged from 0.05% to 0.11%.

[5] Each series of these bonds is supported by a separate direct-pay letter of credit that expires on May 31, 2016. Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.

[6] These bonds bore interest at 2.25% per year through April 1, 2012; and were subject to mandatory tender on April 2, 2012. The Utility repurchsaed these bonds on April 2, 2012 and continues to hold them.

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Derivatives And Hedging Activities (Gains And Losses On Derivative Instruments) (Details) (PGE Corporation And Utility [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
PGE Corporation And Utility [Member]
Unrealized (loss) gain - regulatory assets and liabilities	$ 391	[1]	$ 21	[1]	$ (260)	[1]
Realized loss-cost of electricity	(486)	[2]	(558)	[2]	(573)	[2]
Realized loss-cost of natural gas	(38)	[2]	(106)	[2]	(79)	[2]
Total commodity risk instruments	$ (133)		$ (643)		$ (912)

[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.

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Consolidated Statements Of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Revenues
Electric	$ 12,019	$ 11,606	$ 10,645
Natural gas	3,021	3,350	3,196
Total operating revenues	15,040	14,956	13,841
Operating Expenses
Cost of electricity	4,162	4,016	3,898
Cost of natural gas	861	1,317	1,291
Operating and maintenance	6,052	5,466	4,439
Depreciation, amortization, and decommissioning	2,272	2,215	1,905
Total operating expenses	13,347	13,014	11,533
Operating Income	1,693	1,942	2,308
Interest income	7	7	9
Interest expense	(703)	(700)	(684)
Other income, net	70	49	27
Income Before Income Taxes	1,067	1,298	1,660
Income tax provision	262	440	547
Net Income	830	858	1,113
Preferred stock dividend requirement of subsidiary	14	14	14
Preferred stock dividend requirement	14	14	14
Net Income	816	844	1,099
Weighted Average Common Shares Outstanding, Basic	424	401	382
Weighted Average Common Shares Outstanding, Diluted	425	402	392
Net earnings per common share, basic	$ 1.92	$ 2.1	$ 2.86
Net Earnings Per Common Share, Diluted	$ 1.92	$ 2.1	$ 2.82
Dividends Declared Per Common Share	$ 1.82	$ 1.82	$ 1.82
Pacific Gas And Electric Company [Member]
Operating Revenues
Electric	12,014	11,601	10,644
Natural gas	3,021	3,350	3,196
Total operating revenues	15,035	14,951	13,840
Operating Expenses
Cost of electricity	4,162	4,016	3,898
Cost of natural gas	861	1,317	1,291
Operating and maintenance	6,045	5,459	4,432
Depreciation, amortization, and decommissioning	2,272	2,215	1,905
Total operating expenses	13,340	13,007	11,526
Operating Income	1,695	1,944	2,314
Interest income	6	5	9
Interest expense	(680)	(677)	(650)
Other income, net	88	53	22
Income Before Income Taxes	1,109	1,325	1,695
Income tax provision	298	480	574
Net Income	811	845	1,121
Preferred stock dividend requirement	14	14	14
Net Income	$ 797	$ 831	$ 1,107

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Summary Of Significant Accounting Policies (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Gross carrying amount	$ 110	$ 112
Benefits and customers payments received on tax equity agreements	228
Estimated cost recovery on spent nuclear fuel storage proceeding every year	25
Percentage of recognized tax benefits	50.00%
Percentage of ownership of subsidiaries that are included on federal tax return	80.00%
Disallowed capital expenditure losses	353		36
Spent fuel costs incurred through 2010	266
Increase of estimated cost to decommision nuclear power plant	1,400
Pacific Gas And Electric Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Utility's equity investment in PERF	100.00%
PGE Corporation And Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Loss on debt extinguishment	163	186	186
Amortization on loss on debt extinguishment	23	18	23
Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Composite depreciation rate	3.63%	3.67%	3.38%
AFUDC interest recorded	107	87	110
AFUDC equity recorded	49	40	50
Amortization expense	2	3	4
2013								3
2014							3
2015						3
2016					3
2017				3
Nuclear decommissioning obligation accrued	2,500	1,200
Estimated cost recovery on spent nuclear fuel storage proceeding every year	3,500	2,300
Approximate estimated nuclear decommissioning cost in future dollars	6,100	4,400
Residential And Commercial Retail Solar Energy Installations [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Payments made under tax equity agreements	396
Lease Payments And Investment Contributions [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Payments made under tax equity agreements	361
Hydroelectric Facility Licenses And Other Agreements [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Accumulated amortization	$ 49	$ 47
Hydroelectric Facility Licenses And Other Agreements [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Usefull Life	19 years	19 years
Hydroelectric Facility Licenses And Other Agreements [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Usefull Life	53 years	53 years

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Commitments And Contingencies (Schedule Of Capacity Payments Due Under The QF Contracts Discount) (Details) (USD $) In Millions, unless otherwise specified			12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Maximum [Member] Qualifying Facilities [Member]	Dec. 31, 2012 Minimum [Member] Qualifying Facilities [Member]
Long-term Purchase Commitment [Line Items]
2013	$ 35
2014	27
2015	24
2016	22
2017	18
Thereafter	20
Total fixed capacity payments	146
Less: amount representing interest	21
Present value of fixed capacity payments	125
Capital lease expiration dates of contracts			2014-04-01	2021-09-01
Present value of fixed capacity payments, portion classified as current liabilities	29	36
Present value of fixed capacity payments, portion classified as noncurrent liabilities	96	212
Capitalized asset for fixed capacity payments for corresponding assets	125	248
Capitalized asset for fixed capacity payments, accumulated amortization	$ 148	$ 160

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Restricted cash	$ 330	$ 380
Allowance for doubtful accounts	87	81
Regulatory assets current	564	1,090
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	800,000,000	800,000,000
Common stock, shares outstanding	430,718,293	412,257,082
Energy Recovery Bonds [Member]
Restricted cash	0	51
Allowance for doubtful accounts	0	336
Pacific Gas And Electric Company [Member]
Restricted cash	330	380
Allowance for doubtful accounts	87	81
Regulatory assets current	564	1,090
Common stock, par value	$ 5	$ 5
Common stock, shares authorized	800,000,000	800,000,000
Common stock, shares outstanding	264,374,809	264,374,809
Pacific Gas And Electric Company [Member] | Energy Recovery Bonds [Member]
Restricted cash	0	51
Regulatory assets current	$ 0	$ 336

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Commitments And Contingencies (Third-Party Power Purchase Agreements) (Details)	12 Months Ended
	Dec. 31, 2012
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase of electric power, number of QF's	180
Qualifying Facilities [Member]
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase of electric power, date of contract expiration, beginning date	2013
Long term contract for purchase of electric power, date of contract expiration, ending date	2028
Renewable Energy Power Purchase Agreements [Member]
Third-Party Power Purchase Agreements [Line Items]
Minimum eligible renewable resources of total retail sales for purchasing renewable energy	33.00%

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Common Stock And Share-Based Compensation (Restricted Stock Units) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 years	Dec. 31, 2011	Dec. 31, 2010
Common Stock And Share-Based Compensation [Abstract]
Restricted stock units terms, percentage of shares to vest	20.00%
Restricted stock units terms, percentage of shares to vest, remaining percentage	40.00%
Weighted average grant-date fair value of RSU's	$ 42.17	$ 45.1	$ 42.97
Total fair value	$ 18	$ 11	$ 5
Total unrecognized compensation costs	$ 44
Remaining weighted average period, Years	2.19
Nonvested at January 1, Number of Restricted Stock Units	1,626,048
Granted, Number of Restricted Stock Units	923,001
Vested, Number of Restricted Stock Units	(424,034)
Forfeited, Number of Restricted Stock Units	(55,724)
Nonvested at December 31, Number of Restricted Stock Units	2,069,291	1,626,048
Nonvested at January 1, Weighted Average Grant-Date Fair Value	$ 42.57
Granted, Weighted Average Grant Date Fair Value	$ 42.17
Vested, Weighted Average Grant Date Fair Value	$ 41.88
Forfeited, Weighted Average Grant Date Fair Value	$ 42.64
Nonvested at December 31, Weighted Average Grant-Date Fair Value	$ 42.52	$ 42.57

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Commitments And Contingencies (Other Commitments And Other Operating Leases) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 years	Dec. 31, 2011	Dec. 31, 2010
Commitments And Contingencies [Abstract]
2013	$ 42
2014	37
2015	32
2016	31
2017	24
Thereafter	206
Total	372
Payments for other commitments and operating leases	$ 32	$ 27	$ 25
Expiration dates on operating leases beginning date	2013
Expiration dates on operating leases ending date	2023
Operating rental leases, annual percentage increase, low end	2.00%
Operating rental leases, annual percentage increase. high end	5.00%
Operating rental leases, extension options years, low end	1
Operating rental leases, extension options years, high end	5

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Taxes [Abstract]

Schedule Of Components Of Income Tax Expense (Benefit)

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2012		2011		2010		2012		2011		2010
Current:
Federal	$	(74)	$	(77)	$	(12)	$	(52)	$	(83)	$	(54)
State		33		152		130		41		161		134
Deferred:
Federal		374		504		525		404		534		589
State		(92)		(135)		(91)		(91)		(128)		(90)
Tax credits		(4)		(4)		(5)		(4)		(4)		(5)
Income tax provision	$	237	$	440	$	547	$	298	$	480	$	574

Schedule Of Deferred Tax Assets And Liabilities

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2012		2011		2012		2011
Deferred income tax assets:
Customer advances for construction	$	101	$	108	$	101	$	108
Reserve for damages		175		243		175		243
Environmental reserve		97		157		97		157
Compensation		229		310		179		258
Net operating loss carry forward		938		728		736		567
Other		264		217		255		180
Total deferred income tax assets	$	1,804	$	1,763	$	1,543	$	1,513
Deferred income tax liabilities:
Regulatory balancing accounts	$	256	$	643	$	256	$	643
Property related basis differences		7,449		6,544		7,447		6,536
Income tax regulatory asset		663		588		663		588
Other		173		192		99		105
Total deferred income tax liabilities	$	8,541	$	7,967	$	8,465	$	7,872
Total net deferred income tax liabilities	$	6,737	$	6,204	$	6,922	$	6,359
Classification of net deferred income tax liabilities:
Included in current liabilities (assets)	$	(11)	$	196	$	(17)	$	199
Included in noncurrent liabilities		6,748		6,008		6,939		6,160
Total net deferred income tax liabilities	$	6,737	$	6,204	$	6,922	$	6,359

Schedule Of Effective Income Tax Rate Reconciliation

	PG&E Corporation						Utility
	Year Ended December 31,
	2012		2011		2010		2012		2011		2010
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)	(3.9)		1.1		0.7		(3.0)		1.6		1.0
Effect of regulatory treatment
of fixed asset differences	(4.1)		(4.4)		(3.1)		(3.9)		(4.2)		(3.0)
Tax credits	(0.6)		(0.5)		(0.4)		(0.6)		(0.5)		(0.4)
Benefit of loss carryback	(0.7)		(1.9)		-		(0.4)		(2.1)		-
Non deductible penalties	0.6		6.5		0.2		0.5		6.3		0.2
Other, net	(3.8)		(1.5)		0.8		(0.8)		0.1		1.1
Effective tax rate	22.5	%	34.3	%	33.2	%	26.8	%	36.2	%	33.9	%

Schedule Of Change In Unrecognized Tax Benefits

	PG&E Corporation						Utility
	2012		2011		2010		2012		2011		2010
(in millions)
Balance at beginning of year	$	506	$	714	$	673	$	503	$	712	$	652
Additions for tax position taken
during a prior year		32		2		27		26		2		27
Reductions for tax position
taken during a prior year		(13)		(198)		(20)		(10)		(196)		-
Additions for tax position
taken during the current year		67		3		89		67		-		87
Settlements		(11)		(15)		(55)		(11)		(15)		(54)
Balance at end of year	$	581	$	506	$	714	$	575	$	503	$	712

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Income Taxes (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year	$ 18
Aggregate amount of federal capital loss carryforwards	2,100
Tax credit carryforwards, expiration amount	12
Loss carryforwards, charitable contribution	128
Tax benefit from employee stock plans	$ 19
Tax Credit Carryforward Expiration Date [Minimum]	Dec. 31, 2029
Tax Credit Carryforward Expiration Date [Maximum]	Dec. 31, 2032
Charitable Contribution Carryforward Expiration Date [Minimum]	Dec. 31, 2013
Charitable Contribution Carryforward Expiration Date [Maximum]	Dec. 31, 2017

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Resolution Of Remaining Chapter 11 Disputed Claims

12 Months Ended

Dec. 31, 2012

Resolution Of Remaining Chapter 11 Disputed Claims

NOTE 13: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility's Chapter 11 proceeding 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 governmental entities, for overcharges incurred in the CAISO and the PX wholesale electricity markets during this period. It is uncertain when all these FERC and judicial proceedings will be finally resolved.  

While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers.  The Utility entered into a number of settlement agreements 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.  Additional settlement discussions with other electricity suppliers are ongoing.  Any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers through resolution of the remaining disputed claims, either through settlement or through the conclusion of the various FERC and judicial proceedings, are refunded to customers through rates in future periods.

On April 10, 2012, the Utility received from the PX a letter stating the mutual intent of the CAISO and the PX to offset the Utility's remaining disputed claims with its accounts receivable from the CAISO and the PX.  Accordingly, the Utility has presented the net amount of remaining disputed claims and accounts receivable on the Consolidated Balance Sheets at December 31, 2012, reflecting its intent and right to offset these amounts.  At December 31, 2011, $494 million was included within accounts receivable - other on the Consolidated Balance Sheets.

The following table presents the changes in the remaining net disputed claims liability, which includes interest:

(in millions)
Balance at December 31, 2011	$	848
Interest accrued		27
Less: supplier settlements		(33)
Balance at December 31, 2012	$	842

At December 31, 2012, the remaining net disputed claims liability consisted of $157 million of remaining net disputed claims (classified on the Consolidated Balance Sheets within accounts payable - disputed claims and customer refunds) and $685 million of accrued interest (classified on the Consolidated Balance Sheets within interest payable).

At December 31, 2012 and December 31, 2011, the Utility held $291 million and $320 million, respectively, in escrow, including earned interest, for payment of the remaining net disputed claims liability.  These amounts are included within restricted cash on the Consolidated Balance Sheets.

Interest accrues on the remaining net 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 in rates, these collections are not held in escrow.  If the amount of accrued interest is greater than the amount of interest ultimately determined to be owed on the remaining net disputed claims, the Utility would refund to customers any excess interest collected.  The amount of any interest that the Utility may be required to pay will depend on the final determined amount of the remaining net disputed claims and when such interest is paid.

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Derivatives And Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2012

Derivatives And Hedging Activities [Abstract]

Volumes Of Outstanding Derivative Contracts

2012		Contract Volume (1)
			1 Year or	3 Years or
			Greater but	Greater but
		Less Than 1	Less Than 3	Less Than 5	5 Years or
Underlying Product	Instruments	Year	Years	Years	Greater (2)
Natural Gas (3)	Forwards and
(MMBtus (4))	Swaps	329,466,510	98,628,398	5,490,000	-
	Options	221,587,431	216,279,767	10,050,000	-
Electricity	Forwards and
(Megawatt-hours)	Swaps	2,537,023	3,541,046	2,009,505	2,538,718
	Options	-	239,015	239,233	119,508
	Congestion
	Revenue Rights	74,198,690	74,187,803	74,240,147	25,699,804

⁽¹⁾ Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each period.

⁽²⁾ Derivatives in this category expire between 2018 and 2023.

⁽³⁾ Amounts shown are for the combined positions of the electric fuels and core gas portfolios.

⁽⁴⁾ Million British Thermal Units.

2011		Contract Volume (1)
			1 Year or	3 Years or
			Greater but	Greater but
		Less Than 1	Less Than 3	Less Than 5	5 Years or
Underlying Product	Instruments	Year	Years	Years	Greater (2)
Natural Gas (3)	Forwards and
(MMBtus (4))	Swaps	500,375,394	212,088,902	6,080,000	-
	Options	257,766,990	336,543,013	-	-
Electricity	Forwards and
(Megawatt-hours)	Swaps	4,718,568	5,206,512	2,142,024	3,754,872
	Options	1,248,000	132,048	264,348	264,096
	Congestion
	Revenue Rights	84,247,502	72,882,246	72,949,250	61,673,535

⁽¹⁾ Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each period.

⁽²⁾ Derivatives in this category expire between 2017 and 2022.

⁽³⁾ Amounts shown are for the combined positions of the electric fuels and core gas portfolios.

⁽⁴⁾ Million British Thermal Units.

Outstanding Derivative Balances

2012	Commodity Risk
	Gross Derivative						Total Derivative
(in millions)	Balance		Netting		Cash Collateral		Balance
Current assets - other	$	48	$	(25)	$	36	$	59
Other noncurrent assets - other		99		(11)		-		88
Current liabilities - other		(255)		25		115		(115)
Noncurrent liabilities - other		(221)		11		14		(196)
Total commodity risk	$	(329)	$	-	$	165	$	(164)

2011	Commodity Risk
	Gross Derivative						Total Derivative
(in millions)	Balance		Netting		Cash Collateral		Balance
Current assets - other	$	54	$	(39)	$	103	$	118
Other noncurrent assets - other		113		(59)		-		54
Current liabilities - other		(489)		39		274		(176)
Noncurrent liabilities - other		(398)		59		101		(238)
Total commodity risk	$	(720)	$	-	$	478	$	(242)

Gains And Losses On Derivative Instruments

	Commodity Risk
	For the year ended December 31,
(in millions)	2012		2011		2010
Unrealized gain/(loss) - regulatory assets and liabilities (1)	$	391	$	21	$	(260)
Realized loss - cost of electricity (2)		(486)		(558)		(573)
Realized loss - cost of natural gas (2)		(38)		(106)		(79)
Total commodity risk	$	(133)	$	(643)	$	(912)

⁽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.

Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered

	Balance at December 31,
(in millions)	2012		2011
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(266)	$	(611)
Related derivatives in an asset position		59		86
Collateral posting in the normal course of business related to
these derivatives		103		250
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(104)	$	(275)

 ⁽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.

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Commitments And Contingencies (Nuclear Fuel Agreements) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Long-term Purchase Commitment [Line Items]
2013	$ 3,094
2014	3,434
2015	3,414
2016	3,298
2017	3,140
Thereafter	36,518
Total	52,898
Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Payments for nuclear fuel	118	77	144
Length of contract terms, minimum (in years)	1
Length of contract terms, maximum (in years)	13
Percentage coverage of reactor requirements through 2020	100.00%
Percentage coverage of reactor requirements through 2017	100.00%
Nuclear Fuel Purchase Commitments [Member]
Long-term Purchase Commitment [Line Items]
2013	113
2014	128
2015	194
2016	147
2017	148
Thereafter	878
Total	$ 1,608

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2012

Commitments And Contingencies

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 regulatory proceedings, nuclear operations, legal matters, environmental remediation, and guarantees.

Commitments

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 natural gas or electricity at the date of delivery.  

The costs incurred for all power purchases were as follows:

(in millions)	2012		2011		2010
Qualifying facilities(1)	$	779	$	1,069	$	1,164
Renewable energy contracts		815		622		573
Other power purchase agreements		661		690		657

 ⁽¹⁾ Costs incurred include $286, $297, and $321 attributable to renewable energy contracts with qualifying facilities at December 31, 2012, 2011 and 2010, respectively.

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 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 electrical output and CPUC-approved energy prices.  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, 2012, the Utility had agreements with 180 QFs that are in operation, which expire at various dates between 2013 and 2028.      

Renewable Energy Power Purchase Agreements - The Utility has entered into various contracts to purchase renewable energy to help the Utility meet California's current renewable portfolio standard (“RPS”) requirement.  California's RPS program gradually increases the amount of renewable energy that load-serving entities, such as the Utility, must deliver to their customers from an average of at least 20% of their total retail sales in the years 2011-2013 to 33% of their total retail sales in 2021 and thereafter.  Generally these agreements include an energy payment based on the electrical output and a fixed price per Megawatt-hour.  The Utility's obligations under a significant portion of these agreements are contingent on the third party's construction of new generation facilities.  The table below includes arrangements that have been approved by the CPUC and have completed major milestones with respect to construction.  The Utility's commitments for energy payments under these renewable energy agreements are expected to grow significantly, assuming that the facilities are developed timely.    

Other Power Purchase Agreements - The Utility has entered into several power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements.  The Utility's obligation under a portion of these agreements is contingent on the third parties' development of new generation facilities to provide capacity and energy products to the Utility under tolling agreements.  The Utility also has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

At December 31, 2012, the undiscounted future expected obligations under power purchase agreements were as follows:

				Renewable
(in millions)	Qualifying Facility		(Other than QF)		Other		Total Payments
2013	$	892	$	1,356	$	846	$	3,094
2014		914		1,843		677		3,434
2015		727		2,038		649		3,414
2016		618		2,054		626		3,298
2017		490		2,053		597		3,140
Thereafter		2,238		30,958		3,322		36,518
Total	$	5,879	$	40,302	$	6,717	$	52,898

 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 agreements 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.  

(in millions)
2013	$	35
2014		27
2015		24
2016		22
2017		18
Thereafter		20
Total fixed capacity payments		146
Less: amount representing interest		21
Present value of fixed capacity payments	$	125

Minimum lease payments associated with the lease obligations 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 agreements that are treated as capital leases expire between April 2014 and September 2021.

The present value of the fixed capacity payments due under these agreements is recorded on PG&E Corporation's and the Utility's Consolidated Balance Sheets.  At December 31, 2012 and 2011, current liabilities - other included $29 million and $36 million, respectively, and noncurrent liabilities - other included $96 million and $212 million, respectively.  The corresponding assets at December 31, 2012 and 2011 of $125 million and $248 million including accumulated amortization of $148 million and $160 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 and to fuel its owned-generation facilities.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, 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 natural gas storage services in northern California in order to more reliably meet customers' loads.  

At December 31, 2012, the Utility's undiscounted future expected payment obligations for natural gas supplies, transportation and storage were as follows:

(in millions)
2013	$	707
2014		208
2015		192
2016		152
2017		108
Thereafter		865
Total	$	2,232

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts less than 1 year, amounted to $1.3 billion in 2012, $1.8 billion in 2011, and $1.6 billion in 2010.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements have terms ranging from one to 13 years and are intended to ensure long-term nuclear fuel supply.  The contracts for uranium and for conversion and enrichment services provide for 100% coverage of reactor requirements through 2020, 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.  

At December 31, 2012, the undiscounted future expected payment obligations for nuclear fuel were as follows:

(in millions)
2013	$	113
2014		128
2015		194
2016		147
2017		148
Thereafter		878
Total	$	1,608

Payments for nuclear fuel amounted to $118 million in 2012, $77 million in 2011, and $144 million in 2010.

Other Commitments

The Utility has other commitments relating to operating leases.  At December 31, 2012, the future minimum payments related to these commitments were as follows:

(in millions)
2013	$	42
2014		37
2015		32
2016		31
2017		24
Thereafter		206
Total	$	372

Payments for other commitments relating to operating leases amounted to $32 million in 2012, $27 million in 2011, and $25 million in 2010.  PG&E Corporation and the Utility had operating leases on office facilities expiring at various dates from 2013 to 2023. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 2% to 5%.  The rentals payable under these leases may increase by a fixed amount each year, a percentage of increase over base year, or the consumer price index.  Most leases contain extension options ranging between one and five years.

Underground Electric Facilities

At December 31, 2012, the Utility was committed to spending approximately $277 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 $86 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 that the amount of the capital expenditures will be recoverable from customers through rates.

Contingencies

Legal and Regulatory Contingencies

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 laws and regulations.

PG&E Corporation and the Utility record a provision for a loss when it is both probable that a loss 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 losses and record a provision 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 (or reasonably possible losses in excess of the amounts accrued), 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 the amounts related to such contingencies, PG&E Corporation's and the Utility's policy is to exclude anticipated legal costs.

The accrued liability associated with claims and litigation, regulatory proceedings, penalties, and other legal matters (other than the third-party claims, litigation, and investigations related to natural gas matters that are discussed below) totaled $34 million at December 31, 2012 and $52 million at December 31, 2011 and are 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 and regulatory contingencies would have a material impact on their financial condition, results of operations, or cash flows.  

Natural Gas Matters

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 (the “San Bruno accident”).  The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage.  Following the San Bruno accident, various regulatory proceedings, investigations, and lawsuits were commenced.  The Natural Transportation Safety Board, an independent review panel appointed by the CPUC, and the CPUC's Safety and Enforcement Division (“SED”) completed investigations into the causes of the accident, placing the blame primarily on the Utility.

Pending CPUC Investigations and Enforcement Matters

The CPUC is conducting three investigations pertaining to the Utility's natural gas operations, which are described below.  In 2012, the SED issued reports in each of these investigations alleging that the Utility committed numerous violations of applicable laws and regulations and recommending that the CPUC impose penalties on the Utility.  (See “Penalties Conclusion” below.)  Although the Utility, the SED, and other parties have engaged in settlement discussions in an effort to reach a stipulated outcome to resolve the investigations, the parties have not reached an agreement.  PG&E Corporation and the Utility are uncertain whether or when any stipulated outcome might be reached.  Any agreement regarding a stipulated outcome would be subject to CPUC approval.

The CPUC has concluded evidentiary hearings in each investigation.  The CPUC administrative law judges (“ALJs”) who oversee the investigations have adopted a revised procedural schedule, including the dates by which the parties' briefs must be submitted.  The ALJs have also permitted the other parties (the City of San Bruno, The Utility Reform Network, and the City and County of San Francisco) to separatley address in their opening briefs their allegations against the Utility, if any, in addition to the allegations made by the SED.  The ALJs have ordered the SED and other parties to file single coordinated briefs to address potential monetary penalties and remedies (which could include remedial operational or policy measures) for all three investigations by April 26, 2013.  After briefing has been completed, the ALJs will issue one or more presiding officer's decisions listing the violations determined to have been committed, the amount of penalties, and any required remedial actions.  Based on the revised procedural schedule, one or more presiding officer's decisions will be issued by July 23, 2013.  The decisions would become the final decisions of the CPUC thirty days after issuance unless the Utility or another party filed an appeal, or a CPUC commissioner requested review of the decision, within such time.

CPUC Investigation Regarding the Utility's Facilities Records for its Natural Gas Pipelines

In February 2011, the CPUC commenced an investigation pertaining to safety recordkeeping for Line 132, as well as for the Utility's entire gas transmission system.  Among other matters, the investigation will determine whether the San Bruno accident would have been preventable by the exercise of safe procedures and /or accurate and technical recordkeeping in compliance with the law.  In March 2012, the SED submitted testimony alleging that the Utility committed numerous violations of applicable laws and regulations based on the findings of the SED's records management consultant and an engineering consultant.  Among other findings, the consultants' reports concluded that: the Utility's recordkeeping practices have been deficient and have diminished pipeline safety; the San Bruno accident may have been prevented had the Utility managed its records properly over the years; and that the Utility has been operating, and continues to operate, without a functional integrity management program.  The Utility submitted testimony to the CPUC that acknowledged that improvements are needed to its asset management system and recordkeeping practices, but disputed many of the SED's findings and allegations.  The CPUC concluded evidentiary hearings in this investigation in January 2013.  Briefing on the issue of alleged violations is scheduled to be completed on April 19, 2013.

CPUC Investigation Regarding the Utility's Class Location Designations for Pipelines

             In November 2011, the CPUC commenced an investigation pertaining to the Utility's operation of its natural gas transmission pipeline system in or near locations of higher population density.  Under federal and state regulations, the class location designation of a pipeline is based on the types of buildings, population density, or level of human activity near the segment of pipeline, and is used to determine the maximum allowable operating pressure up to which a pipeline can be operated.  In its May 2012 investigative report, the SED cited the Utility's admissions in previous reports to the CPUC that it had failed to classify pipeline segments properly and to document past patrols of transmission lines and concluded that these failures resulted in over three thousand violations of state and federal standards.  On July 23, 2012, the Utility submitted testimony in response to the SED's report that acknowledged deficiencies in the Utility's past class location and patrol processes and described the efforts to improve those processes.  The CPUC concluded evidentiary hearings in this investigation in September 2012 and briefing on the issue of alleged violations has been completed.

CPUC Investigation Regarding the San Bruno Accident

In January 2012, the CPUC commenced an investigation to determine whether the Utility violated applicable laws and requirements in connection with the San Bruno accident, as alleged by the SED.  In its January investigative report, the SED alleged that the San Bruno accident was caused by the Utility's failure to follow accepted industry practice when installing the section of pipe that failed, the Utility's failure to comply with federal pipeline integrity management requirements, the Utility's inadequate record keeping practices, deficiencies in the Utility's data collection and reporting system, the Utility's inadequate procedures to handle emergencies and abnormal conditions, the Utility's deficient emergency response actions after the incident, and a systemic failure of the Utility's corporate culture that emphasized profits over safety.  The CPUC stated that the scope of the investigation will include all past operations, practices and other events or courses of conduct that could have led to or contributed to the San Bruno accident, as well as, the Utility's compliance with CPUC orders and resolutions issued since the date of the San Bruno accident.   

The Utility submitted testimony to the CPUC that acknowledged its liability for the San Bruno accident and, based on testimony from an expert witness, stated that the likely root cause of the pipeline rupture was: (1) a missing interior weld on the pipe; (2) a ductile tear on the pipe likely caused by a hydrostatic test performed in 1956 at too low a pressure to cause the defective weld to fail; and (3) a fatigue crack on the pipe that grew over time.  However, the Utility stated that many of the findings identified in the SED's reports are not deficiencies, or are much less severe than alleged, and do not constitute violations of applicable laws and regulations.  The CPUC concluded evidentiary hearings in this investigation in January 2013.  Briefing on the issue of alleged violations is scheduled to be completed on April 12, 2013.

Other Potential Enforcement Matters

California gas corporations are required to provide notice to the CPUC of any self-identified or self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and the corporations' natural gas operating practices.  The CPUC has authorized the SED to issue citations and impose penalties based on self-reported violations.  In April 2012, the CPUC affirmed a $17 million penalty that had been imposed by the SED based on the Utility's self-report that it failed to conduct periodic leak surveys because it had not included 16 gas distribution maps in its leak survey schedule.  (The Utility has paid the penalty and completed all of the missed leak surveys.)  As of December 31, 2012, the Utility has submitted 34 self-reports with the CPUC, plus additional follow-up reports.  The SED has not yet taken formal action with respect to the Utility's other self-reports.  The SED may issue additional citations and impose penalties on the Utility associated with these or future reports that the Utility may file.  (See “Penalties Conclusion” below.)

In addition, in July 2012, the Utility reported to the CPUC that it had discovered that its access to some pipelines has been limited by vegetation overgrowth or building structures that encroach upon some of the Utility's gas pipeline rights-of-way.  The Utility is undertaking a system-wide effort to identify and remove encroachments from its pipeline rights-of-way over a multi-year period.  PG&E Corporation and the Utility are uncertain how this matter will affect the above investigative proceedings related to natural gas operations, or whether additional proceedings or investigations will be commenced that could result in regulatory orders or the imposition of penalties on the Utility.

Penalties Conclusion  

The CPUC can impose penalties of up to $20,000 per day, per violation.  (For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation.)  The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged.  The CPUC has historically exercised this wide discretion in determining penalties.  The CPUC's delegation of enforcement authority to the SED allows the SED to use these factors in exercising discretion to determine the number of violations, but the SED is required to impose the maximum statutory penalty for each separate violation that the SED finds.

The CPUC has stated that it is prepared to impose significant penalties on the Utility if the CPUC determines that the Utility violated applicable laws, rules, and orders.  In determining the amount of penalties the ALJs may consider the testimony of financial consultants engaged by the SED and the Utility.  The SED's financial consultant prepared a report concluding that PG&E Corporation could raise approximately $2.25 billion through equity issuances, in addition to equity PG&E Corporation had already forecasted it would issue in 2012, to fund CPUC-imposed penalties on the Utility.  The Utility's financial consultant disagreed with this financial analysis and asserted that a fine in excess of financial analysts' expectations, which the consultant's report cited as a mean of $477 million, would make financing more difficult and expensive.   The ALJs have scheduled a hearing to be held on March 4 and March 5, 2013 to consider the SED's and Utility's testimony.  The SED and other parties are scheduled to file briefs to address potential monetary penalties and remedies in all three investigations by April 26, 2013.  

PG&E Corporation and the Utility believe it is probable that the Utility will incur penalties of at least $200 million in connection with these pending investigations and potential enforcement matters and have accrued this amount in their consolidated financial statements.  PG&E Corporation and the Utility are unable to make a better estimate of probable losses or estimate the range of reasonably possible losses in excess of the amount accrued due to the many variables that could affect the final outcome of these matters and the ultimate amount of penalties imposed on the Utility could be materially higher than the amount accrued.  These variables include how the CPUC and the SED will exercise their discretion in calculating the amount of penalties, including how the total number of violations will be counted; how the duration of the violations will be determined; whether the amount of penalties in each investigation will be determined separately or in the aggregate; how the financial resources testimony submitted by the SED and the Utility will be considered; whether the Utility's costs to perform any required remedial actions will be considered; and whether and how the financial impact of non-recoverable costs the Utility has already incurred, and will continue to incur, to improve the safety and reliability of its pipeline system, will be considered.  (See “CPUC Gas Safety Rulemaking Proceeding” below.)   

These estimates, and the assumptions on which they are based, are subject to change based on many factors, including rulings, orders, or decisions that may be issued by the ALJs; whether the outcome of the investigations is resolved through a fully litigated process or a stipulated outcome that is approved by the CPUC; whether the SED will take additional action with respect to the Utility's self-reports; and whether the CPUC or the SED takes any action with respect to the encroachment matter described above.  Future changes in these estimates or the assumptions on which they are based could have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

CPUC Gas Safety Rulemaking Proceeding

The CPUC is conducting a rulemaking proceeding to adopt new safety and reliability regulations for natural gas transmission and distribution pipelines in California and the related ratemaking mechanisms.  On December 20, 2012, the CPUC approved the Utility's proposed pipeline safety enhancement plan (filed in August 2011) to modernize and upgrade its natural gas transmission system but disallowed the Utility's request for rate recovery of a significant portion of plan-related costs the Utility forecasted it would incur over the first phase of the plan (2011 through 2014).  The CPUC decision limited the Utility's recovery of capital expenditures to $1.0 billion of the total $1.4 billion requested.  Various parties have asked the CPUC to reconsider its decision, arguing that the Utility's cost recovery should be more limited.  For 2012, the Utility recorded a $353 million charge to net income for plan-related capital expenditures incurred that are forecasted to exceed the CPUC's authorized levels or that were specifically disallowed.  Future disallowed amounts will be charged to net income in the period incurred and could have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

Criminal Investigation

In June 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney General's Office, and the San Mateo County District Attorney's Office are conducting an investigation of the San Bruno accident.  Federal and state authorities have indicated that the Utility is a target of the investigation.  The Utility is cooperating with the investigation.  PG&E Corporation and the Utility are uncertain whether any criminal charges will be brought against either company or any of their current or former employees.  PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Utility as a consequence of this investigation.

Third-Party Claims

In addition to the investigations and proceedings discussed above, at December 31, 2012, approximately 140 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, had been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 450 plaintiffs.  The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages.  These cases were coordinated and assigned to one judge in the San Mateo County Superior Court.  Many of the plaintiffs' claims have been resolved through settlements. The trial of the first group of remaining cases began on January 2, 2013 with pretrial motions and hearings. On January 14, 2013, the court vacated the trial and all pending hearings due to the significant number of cases that have been settled outside of court.  The court has urged the parties to settle the remaining cases.  As of February 8, 2013, the Utility has entered into settlement agreements to resolve the claims of approximately 140 plaintiffs.  It is uncertain whether or when the Utility will be able to resolve the remaining claims through settlement.    

At December 31, 2012, the Utility had recorded cumulative charges of $455 million for estimated third-party claims related to the San Bruno accident, including an $80 million charge made during 2012, primarily to reflect settlements and information exchanged by the parties during the settlement and discovery process.  The Utility estimates it is reasonably possible that it may incur as much as an additional $145 million for third-party claims, for a total possible loss of $600 million.  PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with punitive damages, if any, related to these matters.  The Utility has publicly stated that it is liable for the San Bruno accident and will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident.  

The following table presents changes in third-party claims activity since the San Bruno accident in 2010; the balance is included in other current liabilities in PG&E Corporation's and the Utility's Consolidated Balance Sheets:

(in millions)
Balance at January 1, 2010	$	-
Loss accrued		220
Less: Payments		(6	)
Balance at December 31, 2010		214
Additional loss accrued		155
Less: Payments		(92	)
Balance at December 31, 2011		277
Additional loss accrued		80
Less: Payments		(211	)
Balance at December 31, 2012	$	146

Additionally, the Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or “layers.”  Generally, as the policy limit for a layer is exhausted the next layer of insurance becomes available.  The aggregate amount of insurance coverage for third-party liability attributable to the San Bruno accident is approximately $992 million in excess of a $10 million deductible.  The Utility has recognized cumulative insurance recoveries for third-party claims of $284 million, which included $185 million for 2012 and $99 million for 2011.  Although the Utility believes that a significant portion of costs incurred for third-party claims relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries.

Class Action Complaint

On August 23, 2012, a complaint was filed in the San Francisco Superior Court against PG&E Corporation and the Utility (and other unnamed defendants) by individuals who seek certification of a class consisting of all California residents who were customers of the Utility between 1997 and 2010, with certain exceptions.  The plaintiffs allege that the Utility collected more than $100 million in customer rates from 1997 through 2010 for the purpose of various safety measures and operations projects but instead used the funds for general corporate purposes such as executive compensation and bonuses.  To state their claims, the plaintiffs cited the SED's January 2012 investigative report of the San Bruno accident that alleged, from 1996 to 2010, the Utility spent less on capital expenditures and operations and maintenance expense for its natural gas transmission operations than it recovered in rates, by $95 million and $39 million, respectively.  The SED recommended in that report that the Utility should use such amounts to fund future gas transmission expenditures and operations.  Plaintiffs allege that PG&E Corporation and the Utility engaged in unfair business practices in violation of Section 17200 of the California Business and Professions Code (“Section 17200”) and claim that this violation also constitutes a violation of California Public Utilities Code Section 2106 (“Section 2106”), which provides a private right of action for violations of the California constitution or state laws by public utilities.  Plaintiffs seek restitution and disgorgement under Section 17200 and compensatory and punitive damages under Section 2106. 

PG&E Corporation and the Utility contest the plaintiffs' allegations.  In January 2013, PG&E Corporation and the Utility requested that the court dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs' allegations.  In the alternative, PG&E Corporation and the Utility requested that the court stay the proceeding until the CPUC investigations described above are concluded.  The court has set a hearing on the motion for April 26, 2013.  Due to the early stage of this proceeding, PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses that may be incurred in connection with this matter.

Spent Nuclear Fuel Storage Proceedings  

Under the Nuclear Waste Policy Act of 1982, the DOE and electric utilities with commercial nuclear power plants were authorized to enter into contracts under which the DOE would be required to dispose of the utilities' spent nuclear fuel and high-level radioactive waste by January 1998, in exchange for fees paid by the utilities.  The DOE has been unable to meet its contractual obligation to 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 (“Humboldt Bay Unit 3”).  As a result, the Utility constructed an interim dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024, and a separate facility at Humboldt Bay.  The Utility and other nuclear power plant owners sued the DOE to recover the costs that they incurred to construct interim storage facilities for spent nuclear fuel. 

On September 5, 2012, the U.S. Department of Justice and the Utility executed a settlement agreement that awarded the Utility $266 million for spent fuel storage costs incurred through December 31, 2010.  As of December 31, 2012, the Utility has collected the settlement proceeds from the U.S. Treasury and recorded the amount as a regulatory balancing account.  The proceeds will be refunded to customers through rates in future periods. The agreement also allows the Utility to submit annual claims to recover costs incurred in 2011, 2012 and 2013, which the Utility estimates to be approximately $25 million per year.  These amounts will also be refunded to customers in future periods.  At December 31, 2012, PG&E Corporation and the Utility have not recorded any receivables for annual claims in their Consolidated Balance Sheets.  The agreement does not address costs incurred for spent fuel storage after 2013 and such costs could be the subject of future litigation.  Considerable uncertainty continues to exist regarding when and whether the DOE will meet its contractual obligation to the Utility and other nuclear power plant owners to dispose of spent nuclear fuel.

Nuclear Insurance

The Utility is a member of Nuclear Electric Insurance Limited (“NEIL”) which is a mutual insurer owned by utilities with nuclear facilities.  NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility due to a nuclear event (meaning that nuclear material is released) that occurs at the Utility's two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident ($2.7 billion for property damage and $490 million for business interruption) for Diablo Canyon.  In addition, NEIL provides $131 million of coverage for nuclear and non-nuclear property damages at Humboldt Bay Unit 3.  (NEIL also provides insurance coverage to the Utility for non-nuclear property damages and business interruption losses at Diablo Canyon, though with significantly lower limits beginning in April 2013.)  Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss, the Utility may be required to pay an additional premium of up to $44 million per one-year policy term.  NRC regulations require that the Utility's property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident and, second, to decontaminate the plant before any proceeds can be used for decommissioning or plant repair.

NEIL policies also provide coverage for damages caused by acts of terrorism at nuclear power plants.  Certain acts of terrorism may be “certified” by the Secretary of the Treasury.  If damages are 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.  In contrast, NEIL would treat all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share the $3.2 billion policy limit amount.  

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 insurance policies.  The Utility has a separate supplier's and transporter's policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident.

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.

If the Utility incurs losses in connection with any of its nuclear generation facilities that are either not covered by insurance or exceed the amount of insurance available, such losses could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

Environmental Remediation Contingencies

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 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 the Utility can reasonably estimate the loss or a range of probable amounts.  The Utility records an environmental remediation liability based on the lower end of the range of estimated probable 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 following table presents the changes in the environmental remediation liability:

(in millions)
Balance at December 31, 2011	$	785
Additional remediation costs accrued:
Transfer to regulatory account for  recovery		150
Amounts not recoverable from customers		150
Less: Payments		(175)
Balance at December 31, 2012	$	910

The environmental remediation liability is composed of the following:

	Balance at December 31,
(in millions)	2012		2011
Utility-owned natural gas compressor site near Hinkley, California (1)	$	226	$	149
Utility-owned natural gas compressor site near Topock, Arizona (1)		239		218
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites		158		133
Former manufatured gas plant sites owned by the Utility or third parties		181		154
Fossil fuel-fired generation facilities formerly owned by the Utility		87		81
Decommissioning fossil fuel-fired generation facilities and sites		19		50
Total environmental remediation liability	$	910	$	785
(1) See “Natural Gas Compressor Site” below.

The CPUC has authorized the Utility to recover most of its environmental remediation costs through various ratemaking mechanisms, subject to exclusions for certain sites, such as the Hinkley natural gas compressor site, and subject to limitations for certain liabilities such as amounts associated with fossil fuel-fired generation facilities formerly owned by the Utility.  At December 31, 2012, the Utility expected to recover $548 million through these ratemaking mechanisms.  The Utility also recovers environmental remediation costs from insurance carriers and from other third parties whenever possible.  Amounts collected in excess of the Utility's ultimate obligations may be subject to refund to customers through rates.

Natural Gas Compressor Sites

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility's natural gas compressor sites near Hinkley, California (“Hinkley site”) and Topock, Arizona (“Topock site”).  The Utility is also required to take measures to abate the effects of the contamination on the environment.  

Hinkley Site

The Utility's remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region (“Regional Board”).  The Regional Board has issued several orders directing the Utility to implement interim remedial measures to reduce the mass of the underground plume of hexavalent chromium, monitor and control movement of the plume, and provide replacement water to affected residents.  

The Utility submitted its proposed final remediation plan to the Regional Board in September 2011 recommending a combination of remedial methods to clean up groundwater contamination, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water.  In August 2012, the Regional Board issued a draft environmental impact report (“EIR”) that evaluated the Utility's proposed methods and the potential environmental impacts.  The Utility expects that the Regional Board will consider certification of the final EIR in the second quarter of 2013.  Upon certification of the EIR, the Regional Board is expected to issue the final cleanup standards in late 2013.

The Regional Board ordered the Utility in October 2011 to provide an interim and permanent replacement water system for resident households located near the chromium plume that have domestic wells containing hexavalent chromium in concentrations greater than 0.02 parts per billion.  The Utility filed a petition with the California State Water Resources Control Board to contest certain provisions of the order.  In June 2012, the Regional Board issued an amended order to allow the Utility to implement a whole house water replacement program for resident households located near the chromium plume boundary.  Eligible residents may decide whether to accept a replacement water supply or have the Utility purchase their properties, or alternatively not participate in the program.  As of January 31, 2013, approximately 350 residential households are covered by the program and the majority have opted to accept the Utility's offer to purchase their properties.  The Utility is required to complete implementation of the whole house water replacement systems by August 31, 2013.  The Utility will maintain and operate the whole house replacement systems for five years or until the State of California has adopted a drinking water standard specifically for hexavalent chromium at which time the program will be evaluated.

At December 31, 2012 and 2011, $226 million and $149 million, respectively, were accrued in PG&E Corporation's and the Utility's Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley site.  The increase primarily reflects the Utility's best estimate of costs associated with the developments described above.  Remediation costs for the Hinkley natural gas compressor site are not recovered from customers through rates.  Future costs will depend on many factors, including the Regional Board's certification of the final EIR, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the Utility's required time frame for remediation, and adoption of a final drinking water standard currently under development by the State of California, as mentioned above.  As more information becomes known regarding these factors, these estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to further changes.  Future changes in estimates or assumptions may have a material impact on PG&E Corporation's and the Utility's future financial condition, results of operations, and cash flows. 

Topock Site

The Utility's remediation and abatement efforts are subject to the regulatory authority of the Department of Toxic Substances Control (“DTSC”) and the U.S. Department of the Interior (“DOI”).  As directed by the DTSC, 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.  The DTSC has certified the final EIR and approved the Utility's final remediation plan for the groundwater plume, under which the Utility will implement an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium.  The Utility has completed the preliminary design stage for implementing the final groundwater remedy and is required to submit its intermediate design plan to the DTSC and DOI by April 5, 2013 and a final plan for approval in 2014.  In developing its intermediate plan, the Utility is currently evaluating input received from regulatory agencies and other stakeholders, exploring potential sources of fresh water to be used as part of the remedy, and performing other engineering activities necessary to complete the remedial design.

At December 31, 2012 and 2011, $239 million and $218 million, respectively, were accrued in PG&E Corporation's and the Utility's Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Topock site.  The CPUC has authorized the Utility to recover 90% of its remediation costs for the Topock site from customers through rates without a reasonableness review.  As the Utility completes its remedial design plan and more information becomes known regarding the extent of work to be performed to implement the final groundwater remedy, these estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to change.  Future changes in estimates or assumptions could have a material impact on PG&E Corporation's and the Utility's future financial condition.

Reasonably Possible Environmental Contingencies

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility's undiscounted future costs could increase to as much as $1.6 billion (including amounts related to the Hinkley and Topock sites described above) 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.  The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on PG&E Corporation's and the Utility's results of operations during the period in which they are recorded.

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Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pacific Gas And Electric Company [Member]
Federal statutory income tax rate	35.00%	35.00%	35.00%
State income tax (net of federal benefit)	(3.90%)	1.10%	0.70%
Effect of regulatory treatment of fixed asset differences	(4.10%)	(4.40%)	(3.10%)
Tax credits	(0.60%)	(0.50%)	(0.40%)
IRS audit settlements	0.00%	0.00%	0.10%
Benefit of loss carryback	(0.70%)	(1.90%)	0.00%
Non deductible penalties	0.60%	6.50%	0.20%
Other, net	(3.80%)	(1.50%)	0.70%
Effective tax rate	22.50%	34.30%	33.20%
Utility [Member]
Federal statutory income tax rate	35.00%	35.00%	35.00%
State income tax (net of federal benefit)	(3.00%)	1.60%	1.00%
Effect of regulatory treatment of fixed asset differences	(3.90%)	(4.20%)	(3.00%)
Tax credits	(0.60%)	(0.50%)	(0.40%)
IRS audit settlements	0.00%	0.00%	(0.20%)
Benefit of loss carryback	(0.40%)	(2.10%)	0.00%
Non deductible penalties	0.50%	6.30%	0.20%
Other, net	(0.80%)	0.10%	1.30%
Effective tax rate	26.80%	36.20%	33.90%

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Quarterly Consolidated Financial Data (Schedule Of Quarterly Consolidated Financial Data) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating revenues									$ 15,040	$ 14,956	$ 13,841
Operating income									1,693	1,942	2,308
Net income									830	858	1,113
Income available for common shareholders									816	844	1,099
Net earnings per common share, basic									$ 1.92	$ 2.1	$ 2.86
Net earnings per common share, diluted									$ 1.92	$ 2.1	$ 2.82
PG&E Corporation [Member]
Operating revenues	3,830	3,976	3,593	3,641	3,815	3,860	3,684	3,597
Operating income	125	614	467	487	358	408	692	484
Net income	(9)	364	239	236	87	203	366	202	816	844	1,099
Income available for common shareholders	(13)	361	235	233	83	200	362	199	816	844	1,099
Net earnings per common share, basic	$ (0.03)	$ 0.84	$ 0.56	$ 0.56	$ 0.2	$ 0.5	$ 0.91	$ 0.5	$ 1.92	$ 2.1	$ 2.86
Net earnings per common share, diluted	$ (0.03)	$ 0.84	$ 0.55	$ 0.56	$ 0.2	$ 0.5	$ 0.91	$ 0.5	$ 1.92	$ 2.1	$ 2.82
Common stock price per share, High	$ 43.48	$ 46.51	$ 45.2	$ 43.72	$ 43.24	$ 43.32	$ 46.52	$ 47.6
Common stock price per share, Low	$ 39.71	$ 42.41	$ 42.04	$ 40.16	$ 36.86	$ 39.21	$ 41.39	$ 42.47
Utility [Member]
Operating revenues	3,829	3,974	3,592	3,640	3,813	3,859	3,683	3,596
Operating income	127	613	467	488	359	402	699	484
Net income	13	340	227	231	89	196	359	201
Income available for common shareholders	$ 9	$ 337	$ 223	$ 228	$ 85	$ 193	$ 355	$ 198

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Consolidated Statements Of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash Flows from Operating Activities
Net income	$ 830	$ 858	$ 1,113
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,272	2,215	1,905
Allowance for equity funds used during construction	(107)	(87)	(110)
Deferred income taxes and tax credits, net	648	544	756
Disallowed capital expenditures	353	0	36
Other	290	326	257
Effect of changes in operating assets and liabilities:
Accounts receivable	(40)	(288)	(44)
Inventories	(24)	(63)	(43)
Accounts payable	(4)	65	48
Income taxes receivable/payable	(132)	(103)	(78)
Other current assets and liabilities	262	23	111
Regulatory assets, liabilities, and balancing accounts, net	291	(100)	(394)
Other noncurrent assets and liabilities	243	349	(351)
Net cash provided by operating activities	4,882	3,739	3,206
Cash Flows from Investing Activities
Capital expenditures	(4,624)	(4,038)	(3,802)
Decrease in restricted cash	50	200	66
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,133	1,928	1,405
Purchases of nuclear decommissioning trust investments	(1,189)	(1,963)	(1,456)
Other	104	(113)	(70)
Net cash provided by (used in) investing activities	(4,526)	(3,986)	(3,857)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities	120	358	490
Repayments under revolving credit facilities	0	(358)	(490)
Net issuances (repayments) of commercial paper, net of discount of $3 in 2012, $4 in 2011 and $3 in 2010	(1,021)	782	267
Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2010	0	250	249
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $13 in 2012, $8 in 2011, and $23 in 2010	1,137	792	1,327
Short-term debt matured	(250)	(250)	(500)
Long-term debt matured or repurchased	(50)	(700)	(95)
Energy recovery bonds matured	(423)	(404)	(386)
Common stock issued	751	662	303
Common stock dividends paid	(746)	(704)	(662)
Other	14	41	(88)
Net cash provided by (used in) financing activities	(468)	469	415
Net change in cash and cash equivalents	(112)	222	(236)
Cash and cash equivalents at January 1	513	291	527
Cash and cash equivalents at December 31	401	513	291
Cash received (paid) for:
Interest, net of amounts capitalized	(594)	(647)	(627)
Income taxes, net	114	(42)	(135)
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	196	188	183
Capital expenditures financed through accounts payable	362	308	364
Noncash common stock issuances	22	24	265
Terminated Capital Leases	136	0	0
Pacific Gas And Electric Company [Member]
Cash Flows from Operating Activities
Net income	811	845	1,121
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,272	2,215	1,905
Allowance for equity funds used during construction	(107)	(87)	(110)
Deferred income taxes and tax credits, net	684	582	762
Disallowed capital expenditures	353	0	36
Other	236	289	221
Effect of changes in operating assets and liabilities:
Accounts receivable	(40)	(227)	(105)
Inventories	(24)	(63)	(43)
Accounts payable	(26)	51	109
Income taxes receivable/payable	(50)	(192)	(58)
Other current assets and liabilities	272	36	123
Regulatory assets, liabilities, and balancing accounts, net	291	(100)	(394)
Other noncurrent assets and liabilities	256	414	(331)
Net cash provided by operating activities	4,928	3,763	3,236
Cash Flows from Investing Activities
Capital expenditures	(4,624)	(4,038)	(3,802)
Decrease in restricted cash	50	200	66
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,133	1,928	1,405
Purchases of nuclear decommissioning trust investments	(1,189)	(1,963)	(1,456)
Other	16	14	19
Net cash provided by (used in) investing activities	(4,614)	(3,859)	(3,768)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities	0	208	400
Repayments under revolving credit facilities	0	(208)	(400)
Net issuances (repayments) of commercial paper, net of discount of $3 in 2012, $4 in 2011 and $3 in 2010	(1,021)	782	267
Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2010	0	250	249
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $13 in 2012, $8 in 2011, and $23 in 2010	1,137	792	1,327
Short-term debt matured	(250)	(250)	(500)
Long-term debt matured or repurchased	(50)	(700)	(95)
Energy recovery bonds matured	(423)	(404)	(386)
Preferred stock dividends paid	(14)	(14)	(14)
Common stock dividends paid	(716)	(716)	(716)
Equity contribution	885	555	190
Other	28	54	(73)
Net cash provided by (used in) financing activities	(424)	349	249
Net change in cash and cash equivalents	(110)	253	(283)
Cash and cash equivalents at January 1	304	51	334
Cash and cash equivalents at December 31	194	304	51
Cash received (paid) for:
Interest, net of amounts capitalized	(574)	(627)	(595)
Income taxes, net	174	(50)	(171)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	362	308	364
Terminated Capital Leases	$ 136	$ 0	$ 0

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Condensed Consolidated Statements Of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net income	$ 830	$ 858	$ 1,113
Other Comprehensive Income
Unrecognized prior service credit (related to corporation net of income tax of $14, $24 and $20 in 2012, 2011, 2010, respectively and related to utility of $13, $24, and $21, respectively)	17	36	(29)
Unrecognized net loss (related to corporation net of income tax of $20, $452, and $73 in 2012, 2011, and 2010, respectively and related to utility of $22, $447, and $74 respectively)	31	(655)	(110)
Unrecognized net transition obligation (net of income tax of $8 in 2012, and $11 in 2011, 2010, respectively)	16	15	15
Transfer to regulatory account (net of income tax of $30, $408 and $57 in 2012, 2011, and 2010 respectively)	44	593	82
Other (net of income tax of$3 in 2012)	4	0	0
Total other comprehensive income	112	(11)	(42)
Comprehensive income	942	847	1,071
Preferred stock dividend requirement of subsidiary	14	14	14
Comprehensive Income Net Of Tax Attributable To Noncontrolling Interest	928	833	1,057
Pacific Gas And Electric Company [Member]
Net income	811	845	1,121
Other Comprehensive Income
Unrecognized prior service credit (related to corporation net of income tax of $14, $24 and $20 in 2012, 2011, 2010, respectively and related to utility of $13, $24, and $21, respectively)	16	36	(30)
Unrecognized net loss (related to corporation net of income tax of $20, $452, and $73 in 2012, 2011, and 2010, respectively and related to utility of $22, $447, and $74 respectively)	33	(651)	(108)
Unrecognized net transition obligation (net of income tax of $8 in 2012, and $11 in 2011, 2010, respectively)	16	15	15
Transfer to regulatory account (net of income tax of $30, $408 and $57 in 2012, 2011, and 2010 respectively)	44	593	82
Total other comprehensive income	109	(7)	(41)
Comprehensive income	$ 920	$ 838	$ 1,080

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Earnings Per Share

12 Months Ended

Dec. 31, 2012

Earnings Per Share

NOTE 8: EARNINGS PER SHARE

PG&E Corporation's basic earnings per common share (“EPS”) is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.  The following is a reconciliation of PG&E Corporation's income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2012 and 2011.

	Year Ended December 31,
(in millions, except per share amounts)	2012		2011
Income available for common shareholders	$	816	$	844
Weighted average common shares outstanding, basic		424		401
Add incremental shares from assumed conversions:
Employee share-based compensation		1		1
Weighted average common share outstanding, diluted		425		402
Total earnings per common share, diluted	$	1.92	$	2.10

For 2010, PG&E Corporation calculated EPS using the “two-class” method because PG&E Corporation's convertible subordinated notes that were outstanding prior to June 29, 2010 were considered to be participating securities.  In applying the two-class method, undistributed earnings were allocated to both common shares and participating securities. In calculating diluted EPS for 2010, PG&E Corporation applied the “if-converted” method to reflect the dilutive effect of the convertible subordinated notes to the extent that the impact was dilutive when compared to basic EPS.  The following is a reconciliation of PG&E Corporation's income available for common shareholders and weighted average common shares outstanding for calculating basic and diluted EPS for 2010:

	Year Ended December 31, 2010
(in millions, except per share amounts)	Basic		Diluted
Income available for common shareholders	$	1,099	$	1,099
Less: distributed earnings to common shareholders		706		-
Undistributed earnings	$	393	$	1,099
Allocation of earnings to common shareholders
Distributed earnings to common shareholders	$	706	$	-
Undistributed earnings allocated to common shareholders		385		1,099
Add: Interest expense on convertible subordinated notes, net of tax		-		8
Total common shareholders earnings and assumed conversion	$	1,091	$	1,107
Weighted average common shares outstanding		382		382
Add incremental shares from assumed conversions:
Convertible subordinated notes		8		8
Employee share-based compensation		-		2
Weighted average common shares outstanding and participating securities		390		392
Net earnings per common share, basic
Distributed earnings, basic (1)	$	1.85	$	-
Undistributed earnings		1.01		2.82
Total	$	2.86	$	2.82
(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.

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

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Commitments And Contingencies (Change In Accruals Related To Third-Party Claims) (Details) (Pacific Gas And Electric Company [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pacific Gas And Electric Company [Member]
Beginning Balance	$ 277	$ 214
Loss accrued			220
Additional costs accrued	80	155
Less: Payments	(211)	(92)	(6)
Ending Balance	$ 146	$ 277	$ 214

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Commitments And Contingencies (Schedule Of Costs Incurred Attributable To Each Category Of Power Purchase Agreements) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Third-Party Power Purchase Agreements [Line Items]
Payments for renewable energy contracts with QF's	$ 286		$ 297		$ 321
Qualifying Facilities [Member]
Third-Party Power Purchase Agreements [Line Items]
Costs incurred in power purchase	779	[1]	1,069	[1]	1,164	[1]
Renewable Energy Contracts [Member]
Third-Party Power Purchase Agreements [Line Items]
Costs incurred in power purchase	815		622		573
Other Power Purchase Agreements [Member]
Third-Party Power Purchase Agreements [Line Items]
Costs incurred in power purchase	$ 661		$ 690		$ 657

[1] Costs incurred include $286, $297, and $321 attributable to renewable energy contracts with qualifying facilities at December 31, 2012, 2011 and 2010, respectively.

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Resolution Of Remaining Chapter 11 Disputed Claims (Changes In The Remaining Net Disputed Claims Liability) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Escrow for payment of remaining net disputed claims	$ 291	$ 320
Balance at December 31, 2011	848
Interest accrued	27
Less: supplier settlements	(33)
Balance at December 31, 2012	842
Interest payable on disputed claims	685
Pacific Gas And Electric Company [Member]
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Remaining disputed claims	157
CAISO And PX [Member]
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Carrying amounts due from CAISO and PX as of the balance sheet date for disputed claims related to the Chapter 11 Filing		$ 494

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Document And Entity Information (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended			12 Months Ended
	Dec. 31, 2012	Jun. 30, 2012	Feb. 11, 2013 PG&E Corporation [Member]	Dec. 31, 2012 Pacific Gas And Electric Company [Member]	Feb. 11, 2013 Pacific Gas And Electric Company [Member]
Document Type	10-K			10-K
Document Period End Date	Dec. 31, 2012			Dec. 31, 2012
Amendment Flag	false			false
Entity Filer Category	Large Accelerated Filer			Non-accelerated Filer
Entity Registrant Name	PG&E CORP			PACIFIC GAS & ELECTRIC CO
Entity Central Index Key	0001004980			0000075488
Current Fiscal Year End Date	--12-31			--12-31
Document Fiscal Year Focus	2012			2012
Entity Current Reporting Status	Yes			Yes
Document Fiscal Period Focus	FY			FY
Entity Well-known Seasoned Issuer	Yes			Yes
Entity Voluntary Filers	No			No
Entity Public Float		$ 19,276
Entity Common Stock, Shares Outstanding			431,436,673		264,374,809

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Income Taxes

12 Months Ended

Dec. 31, 2012

Income Taxes

NOTE 9: INCOME TAXES

The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2012		2011		2010		2012		2011		2010
Current:
Federal	$	(74)	$	(77)	$	(12)	$	(52)	$	(83)	$	(54)
State		33		152		130		41		161		134
Deferred:
Federal		374		504		525		404		534		589
State		(92)		(135)		(91)		(91)		(128)		(90)
Tax credits		(4)		(4)		(5)		(4)		(4)		(5)
Income tax provision	$	237	$	440	$	547	$	298	$	480	$	574

The following table describes net deferred income tax liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2012		2011		2012		2011
Deferred income tax assets:
Customer advances for construction	$	101	$	108	$	101	$	108
Reserve for damages		175		243		175		243
Environmental reserve		97		157		97		157
Compensation		229		310		179		258
Net operating loss carry forward		938		728		736		567
Other		264		217		255		180
Total deferred income tax assets	$	1,804	$	1,763	$	1,543	$	1,513
Deferred income tax liabilities:
Regulatory balancing accounts	$	256	$	643	$	256	$	643
Property related basis differences		7,449		6,544		7,447		6,536
Income tax regulatory asset		663		588		663		588
Other		173		192		99		105
Total deferred income tax liabilities	$	8,541	$	7,967	$	8,465	$	7,872
Total net deferred income tax liabilities	$	6,737	$	6,204	$	6,922	$	6,359
Classification of net deferred income tax liabilities:
Included in current liabilities (assets)	$	(11)	$	196	$	(17)	$	199
Included in noncurrent liabilities		6,748		6,008		6,939		6,160
Total net deferred income tax liabilities	$	6,737	$	6,204	$	6,922	$	6,359

The following table reconciles income tax expense at the federal statutory rate to the income tax provision:

	PG&E Corporation						Utility
	Year Ended December 31,
	2012		2011		2010		2012		2011		2010
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)	(3.9)		1.1		0.7		(3.0)		1.6		1.0
Effect of regulatory treatment
of fixed asset differences	(4.1)		(4.4)		(3.1)		(3.9)		(4.2)		(3.0)
Tax credits	(0.6)		(0.5)		(0.4)		(0.6)		(0.5)		(0.4)
Benefit of loss carryback	(0.7)		(1.9)		-		(0.4)		(2.1)		-
Non deductible penalties	0.6		6.5		0.2		0.5		6.3		0.2
Other, net	(3.8)		(1.5)		0.8		(0.8)		0.1		1.1
Effective tax rate	22.5	%	34.3	%	33.2	%	26.8	%	36.2	%	33.9	%

Unrecognized tax benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation						Utility
	2012		2011		2010		2012		2011		2010
(in millions)
Balance at beginning of year	$	506	$	714	$	673	$	503	$	712	$	652
Additions for tax position taken
during a prior year		32		2		27		26		2		27
Reductions for tax position
taken during a prior year		(13)		(198)		(20)		(10)		(196)		-
Additions for tax position
taken during the current year		67		3		89		67		-		87
Settlements		(11)		(15)		(55)		(11)		(15)		(54)
Balance at end of year	$	581	$	506	$	714	$	575	$	503	$	712

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2012 for PG&E Corporation and the Utility was $18 million, with the remaining balance representing the potential deferral of taxes to later years.

PG&E Corporation and the Utility recognize accrued interest related to unrecognized tax benefits as income tax expense in the Consolidated Statements of Income.  Interest income and interest expense for the years ended December 31, 2012, December 31, 2011, and December 31, 2010 were immaterial.  

As of December 31, 2012 and December 31, 2011, PG&E Corporation and the Utility had receivables for accrued interest income.  The amounts of these receivables were immaterial.  

The Internal Revenue Service (“IRS”) is working with the utility industry to finalize guidance on what is a repair deduction for tax purposes for the natural gas transmission, natural gas distribution, and electric generation businesses.  PG&E Corporation and the Utility expect the IRS to release this guidance in the first half of 2013.  PG&E Corporation and the Utility expect the unrecognized tax benefits may change significantly within the next 12 months.  

The IRS is auditing a 2008 accounting method change of the Utility to accelerate the amount of deductible repairs.  The audit is expected to be completed in 2013.  The resolution of the audit could result in a significant change in unrecognized tax benefit.  However, PG&E Corporation and the Utility cannot estimate the change of unrecognized tax benefits related to the items discussed above.

Tax settlements and years that remain subject to examination

In 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 its acceptance of the return.  The IRS partially accepted the 2008 return, withholding two matters for further review.  In December 2010, the IRS accepted the 2009 tax return without change.  In September 2011, the IRS partially accepted the 2010 return, withholding two matters for further review.  In September 2012, the IRS partially accepted the 2011 return, withholding several matters for future review.

The most significant of the matters withheld for further review in each of these years relates to a tax accounting method change of the Utility related to repairs.  The IRS has not completed its review of these claims.

Loss carry forwards

As of December 31, 2012, PG&E Corporation had approximately $2.1 billion of federal net operating loss carry forwards and $12 million of tax credit carry forwards, which will expire between 2029 and 2032.  In addition, PG&E Corporation had approximately $128 million of loss carry forwards related to charitable contributions, which will expire between 2013 and 2017.  PG&E Corporation believes it is more likely than not the tax benefits associated with the federal operating loss, charitable contributions, and tax credits can be realized within the carry forward periods, therefore no valuation allowance was recognized as of December 31, 2012.  As of December 31, 2012, PG&E Corporation had approximately $19 million of federal net operating loss carry forwards related to the tax benefit on employee stock plans that would be recorded in additional paid-in capital when used.

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Fair Value Measurements (Level 3 Measurements And Sensitivity Analysis) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012
Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	$ 80,000,000
Liabilities, Fair Value	16,000,000
Fair value measurement Valuation technique	Market approach
Fair value measurement Unobservable Input	CRR auction prices
Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	0
Liabilities, Fair Value	$ 145,000,000
Fair value measurement Valuation technique	Discounted cash flow
Fair value measurement Unobservable Input	Forward prices
Minimum [Member] | CRR Auction Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	(9.04)	[1]
Minimum [Member] | Forward Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	8.59	[1]
Maximum [Member] | CRR Auction Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	55.15	[1]
Maximum [Member] | Forward Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	62.9	[1]

[1] Represents price per megawatt-hour

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Employee Benefit Plans (Schedule Of Employer Contribution Expense) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Employee Benefit Plans [Abstract]
Pension expense	$ 67	$ 65	$ 56

XML

Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Unrecognized prior service credit income tax	$ 14	$ 24	$ 20
Unrecognized net gain, income tax benefit (expense)	20	452	73
Unrecognized net transition obligation income tax	8	11	11
Transfer to regulatory account of income	30	408	57
Other (net of income tax)	3	0	0
Pacific Gas And Electric Company [Member]
Unrecognized prior service credit income tax	13	24	21
Unrecognized net gain, income tax benefit (expense)	22	447	74
Unrecognized net transition obligation income tax	8	11	11
Transfer to regulatory account of income	$ 30	$ 408	$ 57

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Regulatory Assets, Liabilities, And Balancing Accounts

12 Months Ended

Dec. 31, 2012

Regulatory Assets, Liabilities, And Balancing Accounts

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Current Regulatory Assets

At December 31, 2012 and 2011, the Utility had current regulatory assets of $564 million and $1,090 million, respectively.  At December 31, 2012, current regulatory assets consisted primarily of $230 million of the current portion of the price risk management regulatory asset, $62 million of the current portion of the Utility's retained generation regulatory assets, and $54 million of the current portion of the electromechanical meters regulatory asset, each of which is expected to be recovered over the next year.  (See “Long-Term Regulatory Assets” below.)  

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at December 31,
(in millions)	2012		2011
Pension benefits	$	3,275	$	2,899
Deferred income taxes		1,627		1,444
Utility retained generation		552		613
Environmental compliance costs		604		520
Price risk management		210		339
Electromechanical meters		194		247
Unamortized loss, net of gain, on reacquired debt		141		163
Other		206		281
Total long-term regulatory assets	$	6,809	$	6,506

The regulatory asset for pension benefits represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP and also includes amounts that otherwise would be recorded to accumulated other comprehensive loss in the Consolidated Balance Sheets.  (See Note 12 below.)

The regulatory asset for deferred income taxes represents 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.  Based on current regulatory ratemaking and income tax laws, the Utility expects to recover the regulatory asset over the average plant depreciation lives of one to 45 years.

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 12 years.

The regulatory asset for environmental compliance costs represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP.  The Utility expects to recover these costs over the next 32 years, as the environmental compliance work is performed.  (See Note 15 below.)

The regulatory asset for price risk management represents the unrealized losses related to price risk management derivative instruments expected to be recovered as they are realized over the next 10 years as part of the Utility's energy procurement costs.  (See Note 10 below.)

The regulatory asset for electromechanical meters represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices.  The Utility expects to recover the regulatory asset over the next four years.

The regulatory asset for unamortized loss, net of gain, on reacquired debt represents the expected future recovery of 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 14 years, which is the remaining amortization period of the reacquired debt.

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 regulatory assets for retained generation, regulatory assets for electromechanical meters, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Current Regulatory Liabilities

At December 31, 2012 and 2011, the Utility had current regulatory liabilities of $337 million and $161 million, respectively, consisting of amounts that it expects to refund to customers over the next 12 months. At December 31, 2012 current regulatory liabilities primarily included $158 million of ERB over collections, $84 million of proceeds from a greenhouse gas (“GHG”) emission auction to comply with California Air Resources Board requirements, and electricity supplier settlement agreements of $50 million (See Note 13 below).  Current regulatory liabilities are included within 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)	2012		2011
Cost of removal obligations	$	3,625	$	3,460
Recoveries in excess of AROs		620		611
Public purpose programs		590		499
Other		253		163
Total long-term regulatory liabilities	$	5,088	$	4,733

The regulatory liability for cost of removal obligations represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.

The regulatory liability for recoveries in excess of AROs represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the Utility's nuclear generation facilities.  Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust investments.  (See Note 11 below.)

The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances and other energy-using products, the California Solar Initiative program to promote the use of solar energy in homes and commercial, industrial, and agricultural properties, and the Self-Generation Incentive program to promote distributed generation technologies installed on the customer's side of the utility meter.

Regulatory Balancing Accounts

The Utility's current regulatory balancing accounts represent the amounts expected to be collected from or refunded to customers through authorized rate adjustments over the next 12 months.  Regulatory balancing accounts that the Utility does not expect to collect or refund over the next 12 months are included in other noncurrent assets - regulatory assets or noncurrent liabilities - regulatory liabilities, respectively, in the Consolidated Balance Sheets.

Current Regulatory Balancing Accounts, Net

	Receivable (Payable)
	Balance at December 31,
(in millions)	2012		2011
Distribution revenue adjustment mechanism	$	219	$	223
Utility generation		117		241
Hazardous substance		56		57
Public purpose programs		(83)		97
Gas fixed cost		44		16
Energy recovery bonds		(43)		(105)
Energy procurement		77		(48)
Department of Energy Settlement		(250)		-
Other		165		227
Total regulatory balancing accounts, net	$	302	$	708

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 generation balancing account is used to record and recover the authorized revenue requirements associated with Utility-owned electric generation, including capital costs and related non-fuel operating and maintenance expenses.  The recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers fluctuates depending on the volume of electricity sales.  During the colder months of winter, there is generally an under-collection in these balancing accounts due to a lower volume of electricity sales and lower rates.  During the warmer months of summer, there is generally an over-collection due to a higher volume of electricity sales and higher rates.

The hazardous substance balancing accounts are used to record and recover hazardous substance remediation costs that are eligible for recovery through a CPUC-approved ratemaking mechanism.  (See Note 15 below.)

The public purpose programs balancing accounts are primarily used to record and recover the authorized revenue requirements associated with administering public purpose programs, as well as incentive awards earned by the Utility for achieving regulatory targets in the customer energy efficiency programs.  The public purpose programs primarily consist of energy efficiency programs, low-income energy efficiency programs, demand response programs, research, development, and demonstration programs, and renewable energy programs.

The gas fixed-cost balancing account is used to record and recover authorized gas distribution revenue requirements and certain other authorized gas distribution-related costs.  Similar to the utility generation and the distribution revenue adjustment mechanism balancing accounts discussed above, the recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers fluctuates depending on the volume of gas sales.  During the colder months of winter, there is generally an over-collection in this balancing account primarily due to higher natural gas sales.  During the warmer months of summer, there is generally an under-collection primarily due to lower natural gas sales.

The ERBs balancing account is used to record and refund to customers the net refunds, claim offsets, and other credits received by the Utility from electricity suppliers related to Chapter 11 disputed claims and to record and recover authorized ERB servicing costs.  (See Note 13 below.)

The Utility is generally authorized to recover 100% of its prudently incurred electric energy procurement costs.  The Utility tracks energy procurement costs in balancing accounts and files annual forecasts of energy procurement costs that it expects to incur over the following year.  The Utility's energy rates are set to recover such expected costs.

The Department of Energy balancing account is used to record and refund to customers the amounts received from the U.S. Department of Energy (“DOE”) during 2012 for a settlement agreement related to spent nuclear fuel storage costs incurred by the Utility.

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Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Summary Of Significant Accounting Policies

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.  

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.)  

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.  Inventories include natural gas stored underground and materials and supplies.  Natural gas stored underground represents purchases that are recorded to inventory and then expensed at weighted average cost when withdrawn and distributed to customers or used in electric generation.  Materials and supplies are recorded to inventory when purchased and then expensed or capitalized to plant, as appropriate, when consumed or installed.

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 estimated useful lives and balances of its property, plant, and equipment were as follows:

	Estimated Useful	Balance at December 31,
(in millions, except estimated useful lives)	Lives (years)	2012		2011
Electricity generating facilities (1)	10 to 100	$	8,253	$	6,488
Electricity distribution facilities	10 to 55		23,767		22,395
Electricity transmission	10 to 70		7,681		6,968
Natural gas distribution facilities	20 to 53		8,257		7,832
Natural gas transportation and storage	5 to 48		4,314		4,099
Construction work in progress			1,894		1,770
Total property, plant, and equipment			54,166		49,552
Accumulated depreciation			(16,643)		(15,898)
Net property, plant, and equipment		$	37,523	$	33,654
(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.)

Depreciation 

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment in a particular class of property.  This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment.  The Utility's composite depreciation rates were 3.63% in 2012, 3.67% in 2011, and 3.38% in 2010.

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 against 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.

AFUDC

AFUDC is a method used to compensate the Utility for the estimated cost of debt (i.e., interest) and equity funds used to finance regulated plant additions and is capitalized as part of the cost of construction.  AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service.  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 $49 million and $107 million during 2012, $40 million and $87 million during 2011, and $50 million and $110 million during 2010, related to debt and equity, respectively.

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 regulatory assets, 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 in which 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's ability to recover the revenue requirements that have been authorized by the CPUC in a general rate case (“GRC”) and a gas transmission and storage rate case (“GT&S”) does not depend on the volume of the Utility's sales of electricity and natural gas services. The Utility's recovery of a significant portion of its authorized revenue requirements through rates is independent, or “decoupled,” from the volume of electricity and natural gas sales.  

The Utility records differences between actual customer billings and the Utility's authorized revenue requirement, as well as differences between incurred costs and customer billings or authorized revenue meant to recover those costs.  To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account asset or liability, respectively and the differences do not have an impact on net income.  For further discussion, 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 terms ranging from 19 to 53 years.  The gross carrying amount of intangible assets was $110 million at December 31, 2012 and $112 million at December 31, 2011.  The accumulated amortization was $49 million at December 31, 2012 and $47 million at December 31, 2011.

The Utility's amortization expense related to intangible assets was $2 million in 2012, $3 million in 2011, and $4 million in 2010.  The estimated annual amortization expense for 2013 through 2017 based on the December 31, 2012 intangible assets balance is $3 million.  Intangible assets are recorded to other noncurrent assets - other in the Consolidated Balance Sheets.

Asset Retirement Obligations

PG&E Corporation and the Utility record an ARO at discounted fair value in the period in which the obligation is incurred if the discounted 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 ARO is accreted to its present value.  PG&E Corporation and the Utility also record an ARO if a legal obligation to perform an asset removal exists and can be reasonably estimated, but performance is conditional upon a future event.  The Utility recognizes timing differences between the recognition of costs and the costs recovered through the ratemaking process as regulatory assets or liabilities.  (See Note 3 below.)  The Utility has an ARO primarily for its nuclear generation facilities, certain fossil fuel-fired generation facilities, and gas transmission system assets.  

Detailed studies of the cost to decommission the Utility's nuclear generation facilities are conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceedings (“NDCTP”) conducted by the CPUC.  In December 2012, the Utility submitted its updated decommissioning cost estimate with the CPUC.  The estimated undiscounted cost to decommission the Utility's nuclear power plants increased by $1.4 billion due to higher spent nuclear fuel disposal costs and an increase in the scope of work.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear generation facilities.  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.  The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.  A significant portion of the increase in decommissioning cost estimates is due to the need to develop on-site storage for spent nuclear fuel because the federal government has failed to meet its obligation to develop a permanent repository for the disposal of nuclear waste from nuclear facilities in the United States.  The Utility expects that it will recover its future on-site storage costs from the federal government.  The Utility already has recovered $266 million for spent nuclear fuel costs incurred through 2010. (See “Spent Nuclear Fuel Storage Proceedings” in Note 15 below).  Recovered amounts will be refunded to customers through rates.  In its 2012 NDCTP application, the Utility requested that the CPUC issue a final decision by the end of 2013.

The estimated undiscounted nuclear decommissioning cost for the Utility's nuclear generation facilities was approximately $3.5 billion at December 31, 2012 and $2.3 billion at December 31, 2011, as filed in the 2012 and 2009 NDCTPs, respectively.  In future dollars, the estimated nuclear decommissioning cost is approximately $6.1 billion and $4.4 billion, respectively.  These estimates are based on the 2012 and 2009 decommissioning cost studies, respectively, and are prepared in accordance with CPUC requirements.  The estimated nuclear decommissioning cost in future dollars is discounted for GAAP purposes and recognized as an ARO on the Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued in accordance with GAAP was $2.5 billion at December 31, 2012 and $1.2 billion at December 31, 2011.  

A reconciliation of the changes in the ARO liability is as follows:

(in millions)
ARO liability at December 31, 2010	$	1,586
Revision in estimated cash flows		10
Accretion		100
Liabilities settled		(87)
ARO liability at December 31, 2011		1,609
Revision in estimated cash flows		1,301
Accretion		101
Liabilities settled		(92)
ARO liability at December 31, 2012	$	2,919

The Utility has identified the following AROs for which a reasonable estimate of fair value could not be made.  As a result, the Utility has not recorded a liability related to these AROs:  

∙      Restoration of land to its pre-use condition under the terms of certain land rights agreements.  Land rights will be maintained for the foreseeable future, and therefore, the Utility cannot reasonably estimate the settlement date(s) or range of settlement dates for the obligations associated with these assets;  

Removal and proper disposal of lead-based paint contained in some Utility facilities.  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 obligations; and

Removal of certain communications equipment from leased property, and retirement activities associated with substation and certain hydroelectric facilities.  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, expected to be economically beneficial.  Therefore, the settlement date(s) cannot be reasonably estimated at this time.

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge to net income when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.  During 2012, the Utility recorded a $353 million charge to net income for capital expenditures incurred in connection with its pipeline safety enhancement plan that were either specifically disallowed or that are forecasted to exceed the CPUC's authorized levels.  (See “CPUC Gas Safety Rulemaking Proceeding” in Note 15 below).  No material disallowance losses were recorded in 2011 and $36 million in disallowance losses were recorded in 2010.

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 $163 million and $186 million at December 31, 2012 and 2011, respectively.  The amortization expense related to this loss was $23 million in 2012, $18 million in 2011, and $23 million in 2010.  Deferred gains and losses on debt extinguishments are recorded to current assets - regulatory assets 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.

Revenue Recognition

The Utility recognizes revenues as electricity and natural gas services are delivered, and includes amounts for services rendered but not yet billed at the end of the period.  

The CPUC authorizes most of the Utility's revenue requirements in its GRC and its GT&S, which generally occur every three years.  The Utility's ability to recover revenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility's sales of electricity and natural gas services.  The Utility recognizes revenues once they have been authorized for rate recovery, amounts are objectively determinable and probable of recovery, and amounts will be collected within 24 months.  Generally, the revenue recognition criteria are met ratably over the year.  (See Note 3 below.)

The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose, demand response, and customer energy efficiency programs.  Generally, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred.

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.

The Utility's revenues and net income also are affected by incentive ratemaking mechanisms that adjust rates depending on the extent to which the Utility meets certain performance criteria.  

Income Taxes

PG&E Corporation and the Utility use the liability method of accounting for income taxes.  Income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period actual tax expense in addition to calculating deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as depreciation, and are reported within the PG&E Corporation and Utility's balance sheets.  (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.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit.  

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

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 generation facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.  

The Utility classifies its investments held in the nuclear decommissioning trusts as “available-for-sale.”  Since 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 its 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 through rates.  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

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 probable of future recovery through regulated rates, are deferred and recorded in regulatory accounts.  

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 which qualify for the normal purchase and sales exception are not reflected in the Consolidated Balance Sheets at fair value, but are accounted for under the accrual method of accounting.  Therefore, expenses are recognized as incurred.

PG&E Corporation and the Utility offset 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 and the intention to offset exist.  (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.)

Variable Interest Entities

PG&E Corporation and the Utility are required to consolidate the financial results of any entities that they control.  In most cases, control can be determined based on majority ownership or voting interests.  However, there are certain entities known as variable interest entities (“VIEs”) for which control is difficult to discern based on ownership or voting interests alone.  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 in a VIE if it has the obligation to absorb expected losses or the right to receive expected gains that could potentially be significant to the VIE and if it has any decision-making rights associated with the activities that are most significant to the VIE's economic performance, including the power to design the VIE.  An enterprise that has a controlling financial interest in a VIE is known as the VIE's primary beneficiary and is required to consolidate the VIE.

In determining whether consolidation of a particular entity is required, PG&E Corporation and the Utility first evaluate whether the entity is a VIE.  If the entity is a VIE, PG&E Corporation and the Utility use a qualitative approach to determine if either is the primary beneficiary of the VIE.

Some of the counterparties to the Utility's power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility subject to the terms of a power purchase agreement.  In determining whether the Utility is the primary beneficiary of any of these VIEs, it assesses whether it absorbs any of the VIE's expected losses or receives any portion of the VIE's expected residual returns under the terms of the power purchase agreement.  This assessment includes an evaluation of how the risks and rewards associated with the power plant's activities are absorbed by variable interest holders, as well as an analysis of the variability in the VIE's gross margin and the impact of the power purchase agreement on the gross margin.  Under each of these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE.  The Utility does 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 any decision-making rights associated with the design of any VIEs, nor does the Utility have the power to direct the activities that are most significant to the economic performance of any VIEs such as dispatch rights, operating and maintenance activities, or re-marketing activities of the power plant after the termination of any VIE's power purchase agreement with the Utility.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2012, it did not consolidate any of them.

The Utility continued to consolidate the financial results of PG&E Energy Recovery Funding LLC (“PERF”), a VIE, at December 31, 2012, since the Utility is the primary beneficiary of PERF.  PERF was formed in 2005 as a wholly owned subsidiary of the Utility to issue energy recovery bonds (“ERBs”) in connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility's proceeding under Chapter 11 (“Chapter 11 Settlement Agreement”).  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.  PERF is expected to be dissolved in 2013.  (See Note 5 below.)  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 of PG&E Corporation, and the recovery property is not legally an asset of the Utility or PG&E Corporation.

At December 31, 2012, PG&E Corporation affiliates had entered into four tax equity agreements to fund residential and commercial retail solar energy installations with two privately held companies that are considered VIEs.  Under these agreements, PG&E Corporation has agreed to provide lease payments and investment contributions of up to $396 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies.  The majority of these amounts are recorded in other noncurrent assets - other in PG&E Corporation's Consolidated Balance Sheets.  At December 31, 2012, PG&E Corporation had made total payments of $361 million under these agreements and received $228 million in benefits and customer payments.  In determining whether  PG&E Corporation is the primary beneficiary of any of these VIEs, PG&E Corporation assesses which of the variable interest holders has control over these companies' significant economic activities, such as the design of the companies, vendor selection, construction, customer selection, and re-marketing activities after the termination of customer leases. PG&E Corporation determined that these companies control these activities, while its financial exposure from these agreements is generally limited to its lease payments and investment contributions to these companies.  Since PG&E Corporation was not the primary beneficiary of any of these VIEs at December 31, 2012, it did not consolidate any of them.  

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Related Party Agreements And Transactions

12 Months Ended

Dec. 31, 2012

Related Party Agreements And Transactions

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,
(in millions)	2012		2011		2010
Utility revenues from:
Administrative services provided to PG&E Corporation	$	7	$	6	$	7
Utility expenses from:
Administrative services received from PG&E
Corporation	$	50	$	49	$	55
Utility employee benefit due to PG&E Corporation		51		33		27

At December 31, 2012 and 2011, the Utility had receivables of $19 million and $21 million, respectively, from PG&E Corporation included in accounts receivable - other and other noncurrent assets - other on the Utility's Consolidated Balance Sheets, and payables of $17 million and $13 million, respectively, to PG&E Corporation included in accounts payable - other on the Utility's Consolidated Balance Sheets.

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Derivatives And Hedging Activities

12 Months Ended

Dec. 31, 2012

Derivatives And Hedging Activities

NOTE 10: DERIVATIVES

Use of Derivative Instruments

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 and futures contracts that require payments to or from counterparties based upon the difference between two prices for a predetermined contractual quantity; and

• option contracts that provide the Utility with the right to buy a commodity at a predetermined price and option contracts that require payments from counterparties if market prices exceed a predetermined price.

These instruments are not held for speculative purposes and are subject to certain regulatory requirements.  Customer rates are designed to recover the Utility's reasonable costs of providing services, including the costs related to price risk management activities.

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets.  As long as the current ratemaking mechanism discussed above remains in place and the Utility's price risk management activities are carried out in accordance with CPUC directives, the Utility expects to recover fully, in rates, all costs related to derivatives.  Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives 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 commodity derivatives 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 or refund to customers.

The Utility elects the normal purchase and sale exception for eligible derivatives.  Derivatives that require 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 derivatives that are eligible for the normal purchase and sales exception are not reflected in the Consolidated Balance Sheets.

Electricity Procurement

The Utility enters into third-party power purchase agreements for 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 derivatives.  The Utility elects the normal purchase and sale exception for eligible derivatives.

A portion of the Utility's third-party power purchase agreements contain market-based pricing terms.  In order to reduce volatility in customer rates, the Utility may enter into financial swap and/or financial option contracts to effectively fix and/or cap  the price of future purchases and reduce cash flow variability associated with fluctuating electricity prices.  These financial contracts are considered derivatives.

Electric Transmission Congestion Revenue Rights

The California electric transmission grid, controlled by the California Independent System Operator (“CAISO”), is subject to transmission constraints when there is insufficient transmission capacity to supply the market.  The CAISO imposes congestion charges on market participants to manage transmission congestion.  The revenue generated from congestion charges is allocated to holders of congestion revenue rights (“CRRs”).  CRRs allow market participants to hedge the financial risk of CAISO-imposed congestion charges in the 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, such as the Utility, 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 Utility participates in the allocation and auction phases of the annual and monthly CRR processes.  CRRs are considered derivatives.

Natural Gas Procurement (Electric Fuels Portfolio)

The Utility's electric procurement portfolio is exposed to natural gas price risk primarily through physical natural gas commodity purchases to fuel natural gas generating facilities, and electricity procurement contracts indexed to natural gas prices.  To reduce the volatility in customer rates, the Utility may enter into financial swap contracts or financial option contracts, or both.  The Utility also enters into fixed-price forward contracts for natural gas to reduce future cash flow variability from fluctuating natural gas prices.  These instruments are considered derivatives.

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 natural 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 natural gas prices during peak winter months.  These financial instruments are considered derivatives.

Volume of Derivative Activity

At December 31, 2012, the volumes of PG&E Corporation's and the Utility's outstanding derivatives were as follows:

		Contract Volume (1)
			1 Year or	3 Years or
			Greater but	Greater but
		Less Than 1	Less Than 3	Less Than 5	5 Years or
Underlying Product	Instruments	Year	Years	Years	Greater (2)
Natural Gas (3)	Forwards and
(MMBtus (4))	Swaps	329,466,510	98,628,398	5,490,000	-
	Options	221,587,431	216,279,767	10,050,000	-
Electricity	Forwards and
(Megawatt-hours)	Swaps	2,537,023	3,541,046	2,009,505	2,538,718
	Options	-	239,015	239,233	119,508
	Congestion
	Revenue Rights	74,198,690	74,187,803	74,240,147	25,699,804
(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each period. (2) Derivatives in this category expire between 2018 and 2023. (3) Amounts shown are for the combined positions of the electric fuels and core gas portfolios. (4) Million British Thermal Units.

At December 31, 2011, the volumes of PG&E Corporation's and the Utility's outstanding derivatives were as follows:

		Contract Volume (1)
			1 Year or	3 Years or
			Greater but	Greater but
		Less Than 1	Less Than 3	Less Than 5	5 Years or
Underlying Product	Instruments	Year	Years	Years	Greater (2)
Natural Gas (3)	Forwards and
(MMBtus (4))	Swaps	500,375,394	212,088,902	6,080,000	-
	Options	257,766,990	336,543,013	-	-
Electricity	Forwards and
(Megawatt-hours)	Swaps	4,718,568	5,206,512	2,142,024	3,754,872
	Options	1,248,000	132,048	264,348	264,096
	Congestion
	Revenue Rights	84,247,502	72,882,246	72,949,250	61,673,535
(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each period. (2) Derivatives in this category expire between 2017 and 2022. (3) Amounts shown are for the combined positions of the electric fuels and core gas portfolios. (4) Million British Thermal Units.

Presentation of Derivative Instruments in the Financial Statements

In PG&E Corporation's and the Utility's Consolidated Balance Sheets, derivatives are presented on a net basis by counterparty where the right and the intention to offset exists under a master netting agreement.  The net balances include outstanding cash collateral associated with derivative positions.

At December 31, 2012, PG&E Corporation's and the Utility's outstanding derivative balances were as follows:

	Commodity Risk
	Gross Derivative						Total Derivative
(in millions)	Balance		Netting		Cash Collateral		Balance
Current assets - other	$	48	$	(25)	$	36	$	59
Other noncurrent assets - other		99		(11)		-		88
Current liabilities - other		(255)		25		115		(115)
Noncurrent liabilities - other		(221)		11		14		(196)
Total commodity risk	$	(329)	$	-	$	165	$	(164)

At December 31, 2011, PG&E Corporation's and the Utility's outstanding derivative balances were as follows:

	Commodity Risk
	Gross Derivative						Total Derivative
(in millions)	Balance		Netting		Cash Collateral		Balance
Current assets - other	$	54	$	(39)	$	103	$	118
Other noncurrent assets - other		113		(59)		-		54
Current liabilities - other		(489)		39		274		(176)
Noncurrent liabilities - other		(398)		59		101		(238)
Total commodity risk	$	(720)	$	-	$	478	$	(242)

Gains and losses recorded on PG&E Corporation's and the Utility's derivatives were as follows:

	Commodity Risk
	For the year ended December 31,
(in millions)	2012		2011		2010
Unrealized gain/(loss) - regulatory assets and liabilities (1)	$	391	$	21	$	(260)
Realized loss - cost of electricity (2)		(486)		(558)		(573)
Realized loss - cost of natural gas (2)		(38)		(106)		(79)
Total commodity risk	$	(133)	$	(643)	$	(912)

⁽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 derivatives 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 derivatives contain collateral posting provisions tied to the Utility's credit rating from each of the major credit rating agencies.  At December 31, 2012, the Utility's credit rating was investment grade.  If the Utility's credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions.

The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows:

	Balance at December 31,
(in millions)	2012		2011
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(266)	$	(611)
Related derivatives in an asset position		59		86
Collateral posting in the normal course of business related to
these derivatives		103		250
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(104)	$	(275)
(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.

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Employee Benefit Plans (Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.98%	4.66%	5.42%
Average rate of future compensation increases	4.00%	5.00%	5.00%
Expected return on plan assets	5.40%	5.50%	6.60%
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate range	3.75 -4.08	4.41-4.77	5.11-5.56
Expected return on plan assets percentage range	2.90- 6.10	4.40-5.50	5.20-6.60

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Common Stock And Share-Based Compensation

12 Months Ended

Dec. 31, 2012

Common Stock And Share-Based Compensation

NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation

PG&E Corporation had 430,718,293 shares of common stock outstanding at December 31, 2012.  During 2012, PG&E Corporation issued 6,803,101 shares of its common stock under its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and its share-based compensation plans, generating $263 million of cash.

In November 2011, PG&E Corporation entered into an Equity Distribution Agreement providing for the sale of PG&E common stock having an aggregate gross sales 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.  During 2012, PG&E Corporation sold 5,446,760 shares of its common stock under the Equity Distribution Agreement for cash proceeds of $234 million, net of fees.  As of December 31, 2012, PG&E Corporation had the ability to issue an additional $64 million of its common stock under the November 2011 Equity Distribution Agreement.  In March 2012, PG&E Corporation sold 5,900,000 shares of its common stock in an underwritten public offering for cash proceeds of $254 million, net of fees and commissions.

Utility

As of December 31, 2012, PG&E Corporation held all of the Utility's outstanding common stock.  

Dividends

The Board of Directors of PG&E Corporation and the Utility declare dividends quarterly.  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.  In February, June, September, and December, 2012, the Board of Directors of PG&E Corporation declared a quarterly dividend of $0.455 per share.

PG&E Corporation and the Utility each have revolving credit facilities that require the respective company to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%.  Based on the calculation of this ratio for PG&E Corporation, no amount of PG&E Corporation's reinvested earnings was restricted at December 31, 2012.  Based on the calculation of this ratio for the Utility, $1.1 billion of the Utility's reinvested earnings was restricted at December 31, 2012.  In addition, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average.  At December 31, 2012, the Utility was required to maintain reinvested earnings of $6.3 billion as equity to meet this requirement.

In addition, to comply with the revolving credit facility's 65% ratio requirement and the CPUC's requirement to maintain a 52% equity component, $7.0 billion and $12.2 billion of the Utility's net assets, respectively, were restricted at December 31, 2012 and could not be transferred to PG&E Corporation in the form of cash dividends.  As a holding company, PG&E Corporation depends on cash distributions from the Utility to meet its debt service and other financial obligations and to pay dividends on its common stock.

Long-Term Incentive Plan

The PG&E Corporation 2006 Long-Term Incentive Plan (“2006 LTIP”) permits the award of various forms of incentive awards, including stock options, stock appreciation rights, restricted stock awards, restricted stock units (“RSUs”), performance shares, deferred compensation awards, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries.  Non-employee directors of PG&E Corporation are also eligible to receive share-based awards 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 4,548,119 shares were available for award at December 31, 2012.  

The following table provides a summary of total compensation expense for PG&E Corporation for share-based incentive awards for 2012, 2011, and 2010:

(in millions)	2012		2011		2010
Restricted stock units	$	31	$	22	$	9
Other share-based compensation		-		1		14
Performance shares:
Equity awards		26		16		11
Liability awards		-		(13)		22
Total compensation expense (pre-tax)	$	57	$	26	$	56
Total compensation expense (after-tax)	$	34	$	16	$	33

There were no significant share-based compensation costs capitalized during 2012, 2011, and 2010.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Restricted Stock Units

Each RSU represents one hypothetical share of PG&E Corporation common stock.  RSUs 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.  Vested RSUs are settled in shares 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.  RSU 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.

The weighted average grant-date fair value per RSUs granted during 2012, 2011, and 2010 was $42.17, $45.10, and $42.97, respectively.  The total fair value of RSUs that vested during 2012, 2011, and 2010 was $18 million, $11 million, and $5 million, respectively.  The tax benefit from RSUs that vested during 2012, 2011, and 2010 was not material.  As of December 31, 2012, $44 million of total unrecognized compensation costs related to nonvested RSUs was expected to be recognized over the remaining weighted average period of 2.19 years.

The following table summarizes RSU activity for 2012:

	Number of	Weighted Average Grant-
	Restricted Stock Units	Date Fair Value
Nonvested at January 1	1,626,048	$	42.57
Granted	923,001	$	42.17
Vested	(424,034)	$	41.88
Forfeited	(55,724)	$	42.64
Nonvested at December 31	2,069,291	$	42.52

Performance Shares

In 2012, PG&E Corporation granted 834,420 contingent performance shares to eligible employees.  Performance shares vest after three years of service.  Performance shares granted in 2012, 2011, and 2010 are settled in shares of PG&E Corporation common stock and are classified as share-based equity awards.  Performance-based awards granted prior to 2010 are settled in cash and classified as a liability.  The amount of common stock (or cash with respect to grants before 2010) that recipients are entitled to receive, if any, will be determined based on PG&E Corporation's annual total shareholder return relative to the performance of a specified group of peer companies for the applicable three-year performance period.  Total compensation expense for performance 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 performance shares, if any, will be paid in cash upon the vesting date based on the amount of common stock to which the recipients are entitled.  

The weighted average grant-date fair value for performance shares granted during 2012, 2011, and 2010 was $41.93, $33.91, and $35.60 respectively.  There was no tax benefit associated with performance shares that vested during 2012, 2011, and 2010, as awards that settle in cash have no tax impact, and awards that settle in shares do not generate a tax benefit until vested.  The performance shares awarded in March 2010 will vest in March 2013.  As of December 31, 2012, $29 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted average period of 1.28 years.

The following table summarizes performance shares classified as equity awards activity for 2012:

	Number of	Weighted Average Grant-
	Performance Shares	Date Fair Value
Nonvested at January 1	1,325,406	$	34.64
Granted	834,420	$	41.93
Vested	(425)	$	34.86
Forfeited (1)	(661,928)	$	35.71
Nonvested at December 31	1,497,473	$	38.15
(1) Includes performance shares that expired with zero value as performance targets were not met.

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Common Stock And Share-Based Compensation (Performance Shares) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock issued during period, shares, performance share award gross	834,420
Performance period for vesting of performance shares, years	3
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized	$ 29
Weighted-average period (years)	1.28
Performance Shares, Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested at January 1, Number of Performance Shares	1,325,406
Granted, Number of Performance Shares	834,420
Vested, Number of Performance Shares	(425)
Forfeited, Number of Performance Shares	(661,928)	[1]
Nonvested at December 31, Number of Performance Shares	1,497,473		1,325,406
Nonvested at January 1, Weighted Average Exercise Price	$ 34.64
Granted, Weighted Average Exercise Price	41.93		33.91	35.6
Vested, Weighted Average Exercise Price	34.86
Forfeited, Weighted Average Exercise Price	35.71	[1]
Nonvested at December 31, Weighted Average Exercise Price	$ 38.15		$ 34.64

[1] Includes performance shares that expired with zero value as performance targets were not met.

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Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Balance Sheet) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash and cash equivalents	$ 401	$ 513	$ 291	$ 527
Advances to affiliates	17	13
Income taxes receivable	211	183
Total current assets	5,121	6,480
Equipment	54,167	49,567
Accumulated depreciation	16,644	15,912
Net property, plant, and equipment	37,523	33,655
Income taxes receivable	176	386
Other	659	682
TOTAL ASSETS	52,449	49,750
Short-term borrowings	492	1,647
Other	2,012	1,836
Total current liabilities	6,256	7,749
Long-term debt	12,517	11,766
Other	2,020	2,136
Total noncurrent liabilities	32,867	29,648
Common stock	8,428	7,602
Reinvested earnings	4,747	4,712
Accumulated other comprehensive loss	(101)	(213)
Total shareholders' equity	13,074	12,101
TOTAL LIABILITIES AND EQUITY	52,449	49,750
PG&E Corporation [Member]
Cash and cash equivalents	207	209	240	193
Advances to affiliates	26	18
Income taxes receivable	33	8
Deferred income taxes	0	4
Total current assets	226	239
Equipment	1	14
Accumulated depreciation	(1)	(14)
Net property, plant, and equipment	0	0
Investments in subsidiaries	13,387	12,378
Other investments	102	94
Income taxes receivable	5	2
Deferred income taxes	178	143
Other	1	2
Total noncurrent assets	13,673	12,619
TOTAL ASSETS	13,939	12,858
Short-term borrowings	120	0
Accounts payable - other	48	21
Other	221	208
Total current liabilities	289	286
Long-term debt	349	349
Income taxes payable	0	57
Other	127	122
Total noncurrent liabilities	476	471
Common stock	8,428	7,602
Reinvested earnings	4,747	4,712
Accumulated other comprehensive loss	(101)	(213)
Total shareholders' equity	13,074	12,101
TOTAL LIABILITIES AND EQUITY	$ 13,939	$ 12,858

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Debt

12 Months Ended

Dec. 31, 2012

Debt

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)	2012		2011
PG&E Corporation
Senior notes, 5.75%, due 2014		350		350
Unamortized discount		-		(1)
Total senior notes		350		349
Total PG&E Corporation long-term debt		350		349
Utility
Senior notes:
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		800
4.25% due 2021		300		300
3.25% due 2021		250		250
2.45% due 2022		400		-
6.05% due 2034		3,000		3,000
5.80% due 2037		950		950
6.35% due 2038		400		400
6.25% due 2039		550		550
5.40% due 2040		800		800
4.50% due 2041		250		250
4.45% due 2042		400		-
3.75% due 2042		350		-
Less: current portion		(400)		-
Unamortized discount, net of premium		(51)		(51)
Total senior notes, net of current portion		10,899		10,149
Pollution control bonds:
Series 1996 C, E, F, 1997 B, variable rates (1), due 2026 (2)		614		614
Series 2004 A-D, 4.75%, due 2023 (3)		345		345
Series 2009 A-D, variable rates (4), due 2016 and 2026 (5)		309		309
Series 2010 E, 2.25%, due 2026 (6)		-		50
Less: current portion		-		(50)
Total pollution control bonds		1,268		1,268
Total Utility long-term debt, net of current portion		12,167		11,417
Total consolidated long-term debt, net of current portion	$	12,517	$	11,766
1)  At December 31, 2012, interest rates on these bonds and the related loans ranged from 0.10% to 0.14%. (2)  Each series of these bonds is supported by a separate letter of credit that expires on May 31, 2016. 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 consent from the issuer to the continuation of the series without a credit facility. (3) The Utility has obtained credit support from an insurance company for these bonds. (4) At December 31, 2012, interest rates on these bonds and the related loans ranged from 0.05% to 0.11%. (5) Each series of these bonds is supported by a separate direct-pay letter of credit that expires on May 31, 2016.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent. (6) These bonds bore interest at 2.25% per year through April 1, 2012; and were subject to mandatory tender on April 2, 2012.  The Utility repurchased these bonds on April 2, 2012 and continues to hold them.

 ⁽

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.  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 (“Code”), 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 debt principal repayment amounts at December 31, 2012 are reflected in the table below:

(in millions,
except interest rates)	2013			2014				2015			2016				2017			Thereafter				Total
PG&E Corporation
Average fixed interest rate		-				5.75	%			-			-			-				-				5.75	%
Fixed rate obligations	$	-			$	350			$	-		$	-		$	-			$	-			$	350
Utility
Average fixed interest rate		6.25	%			4.80	%			-			-			5.63	%			5.45	%			5.43	%
Fixed rate obligations	$	400			$	1,000			$	-		$	-		$	700			$	9,595			$	11,695
Variable interest rate
as of December 31, 2012		-				-				-			0.11	%		-				-				0.11	%
Variable rate obligations	$	-			$	-			$	-		$	923	(1	)	-			$	-			$	923
Total consolidated debt	$	400			$	1,350			$	-		$	923		$	700			$	9,595			$	12,968
(1) These bonds, due in 2016 and 2026, are backed by letters of credit that expire on May 31, 2016.

Short-term Borrowings

The following table summarizes PG&E Corporation's and the Utility's outstanding borrowings on its revolving credit facilities and commercial paper program at December 31, 2012:

						Letters of
	Termination	Facility				Credit				Commercial				Facility
(in millions)	Date	Limit				Outstanding		Borrowings		Paper				Availability
PG&E Corporation	May 2016	$	300	(1	)	$	-	$	120	$	-			$	180
Utility	May 2016		3,000	(2	)		266		-		370	(3	)		2,364	(3	)
Total revolving credit facilities		$	3,300			$	266	$	120	$	370			$	2,544
(1) Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days. (2) Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days. (3) The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.

For 2012, the average outstanding borrowings on PG&E Corporation's revolving credit facility was $21 million and the maximum outstanding balance during the year was $120 million.  For 2012, the Utility's average outstanding commercial paper balance was $665 million and the maximum outstanding balance during the year was $1.4 billion.  

Revolving Credit Facilities

PG&E Corporation has a $300 million revolving credit facility with a syndicate of lenders.  The Utility has a $3.0 billion revolving credit facility with a syndicate of lenders.  The revolving credit facilities have terms of five years and all amounts are due and payable on the facilities' termination date, May 31, 2016.  At PG&E Corporation's and the Utility's request and at the sole discretion of each lender, the facilities may be extended for additional periods.  The revolving credit facilities may be used for working capital and other corporate purposes.  The Utility's revolving credit facility may also be used for the repayment of commercial paper.  

Provided certain conditions are met, PG&E Corporation and the Utility have the right to increase, in one or more requests, given not more frequently than once a year, the aggregate lenders' commitments under the revolving credit facilities by up to $100 million and $500 million, respectively, in the aggregate for all such increases.

Borrowings under the revolving credit facilities (other than swingline loans) bear interest based, at PG&E Corporation's and the Utility's election, on (1) a London Interbank Offered Rate (“LIBOR”) plus an applicable margin or (2) the base rate plus an applicable margin.  The base rate will equal the higher of the following: the administrative agent's announced base rate, 0.5% above the federal funds rate, or the one-month LIBOR plus an applicable margin.  Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods.  PG&E Corporation and the Utility also will pay a facility fee on the total commitments of the lenders under the revolving credit facilities.  The applicable margins and the facility fees will be based on PG&E Corporation's and the Utility's senior unsecured debt ratings issued by Standard & Poor's Rating Services and Moody's Investor Service.  Facility fees are payable quarterly in arrears.

The revolving credit facilities include usual and customary covenants for revolving credit facilities of this type, including covenants limiting liens to those permitted under PG&E Corporation's and the Utility's senior note indentures, mergers, sales of all or substantially all of PG&E Corporation's and the Utility's assets, and other fundamental changes.  In addition, the revolving credit facilities require that PG&E Corporation and 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.  PG&E Corporation's revolving credit facility agreement also requires that PG&E Corporation 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, 2012, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

Commercial Paper Program

The Utility has a $1.75 billion commercial paper program, the borrowings from which are used primarily to fund temporary financing needs.  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, 2012, the average yield on outstanding commercial paper was 0.36%.

Other Short-term Borrowings

In November 2011, the Utility issued $250 million principal amount of Floating Rate Senior Notes which were due and repaid in November 2012.  For the years ended December 31, 2012 and 2011, the average interest rate on the Floating Rate Senior Notes was 0.92% and 0.94%, respectively.

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Energy Recovery Bonds

12 Months Ended

Dec. 31, 2012

Energy Recovery Bonds

NOTE 5: ENERGY RECOVERY BONDS

In 2005, PERF issued two series of ERBs. The proceeds of the ERBs were used by PERF to purchase from the Utility the right known as “recovery property” to be paid a specific amount from a dedicated rate component.  The first series of ERBs included five classes aggregating to a $1.9 billion principal amount. The proceeds of the first series of ERBs were paid by PERF to the Utility and used by the Utility to refinance the remaining unamortized after-tax balance of the regulatory asset established under the Chapter 11 Settlement Agreement. The second series of ERBs included three classes aggregating to an $844 million principal amount. The proceeds of the second series of ERBs were paid by PERF to the Utility and used to pre-fund the Utility's tax liability for bond-related charges collected from customers.

At December 31, 2011, the total amount of ERB principal outstanding was $423 million. The ERBs were paid in full when the final class matured on December 25, 2012.

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Preferred Stock

12 Months Ended

Dec. 31, 2012

Preferred Stock

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.  PG&E Corporation does not have any preferred stock outstanding.

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, none of which had mandatory redemption provisions at December 31, 2012 and 2011:

(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

At December 31, 2012, annual dividends on the Utility's nonredeemable preferred stock ranged 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, 2012, 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 2012, 2011, and 2010 the Utility paid $14 million of dividends on preferred stock.

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Earnings Per Share (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Shares Of Common Stock Outstanding For Calculating Basic EPS) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Earnings Per Share Basic And Diluted [Line Items]
Net Income	$ 816	$ 844	$ 1,099
Weighted average common shares outstanding, basic	424	401	382
Employee share-based compensation	1	1
Total	$ 1.92	$ 2.1	$ 2.86
Basic [Member]
Earnings Per Share Basic And Diluted [Line Items]
Net Income			1,099
Less: distributed earnings to common shareholders			706
Undistributed earnings			393
Distributed earnings to common shareholders			706
Undistributed earnings allocated to common shareholders			385
Interest on Convertible Debt, Net of Tax			0
Total common shareholders earnings			1,091
Weighted average common shares outstanding, basic			382
Convertible subordinated notes			8
Employee share-based compensation			0
Weighted average common shares outstanding and participating securities			390
Distributed earnings, basic			$ 1.85	[1]
Undistributed earnings			$ 1.01
Total			$ 2.86
Diluted [Member]
Earnings Per Share Basic And Diluted [Line Items]
Net Income			1,099
Less: distributed earnings to common shareholders			0
Undistributed earnings			1,099
Distributed earnings to common shareholders			0
Undistributed earnings allocated to common shareholders			1,099
Interest on Convertible Debt, Net of Tax			8
Total common shareholders earnings			$ 1,107
Weighted average common shares outstanding, basic			382
Convertible subordinated notes			8
Employee share-based compensation			2
Weighted average common shares outstanding and participating securities			392
Distributed earnings, basic			$ 0	[1]
Undistributed earnings			$ 2.82
Total			$ 2.82

[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.

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Employee Benefit Plans (Schedule Of Assumed Health Care Cost Trend) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Employee Benefit Plans [Abstract]
Effect on postretirement benefit obligation, One-Percentage-Point Increase	$ 108
Effect on postretirement benefit obligation, One-Percentage-Point Decrease	(111)
Effect on service and interest cost, One-Percentage-Point Increase	8
Effect on service and interest cost, One-Percentage-Point Decrease	$ (8)
Assumed health care cost trend rate	7.50%
Ultimate trend rate	5.00%
Year of ultimate trend rate	2018
Assumed return	5.40%	5.50%	6.60%
10 year actual rate of return	10.20%
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used	648

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Income Taxes (Schedule Of Income Tax Provision) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current, Federal	$ (74)	$ (77)	$ (12)
Current, State	33	152	130
Deferred, Federal	374	504	525
Deferred, State	(92)	(135)	(91)
Tax credits	(4)	(4)	(5)
Income Tax Provision	262	440	547
Pacific Gas And Electric Company [Member]
Income Tax Provision	298	480	574
Utility [Member]
Current, Federal	(52)	(83)	(54)
Current, State	41	161	134
Deferred, Federal	404	534	589
Deferred, State	(91)	(128)	(90)
Tax credits	(4)	(4)	(5)
Income Tax Provision	$ 298	$ 480	$ 574

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Commitments And Contingencies (Legal And Regulatory Contingencies) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended		12 Months Ended		12 Months Ended				3 Months Ended				12 Months Ended
	Dec. 31, 2012	Dec. 31, 2010	Dec. 31, 2012 PGE Corporation And Utility [Member]	Dec. 31, 2011 PGE Corporation And Utility [Member]	Dec. 31, 2012 Pacific Gas And Electric Company [Member]	Dec. 31, 2011 Pacific Gas And Electric Company [Member]	Feb. 11, 2013 Pacific Gas And Electric Company [Member] plaintiffs	Dec. 31, 2010 Pacific Gas And Electric Company [Member]	Dec. 31, 2012 Utility [Member]	Sep. 30, 2012 Utility [Member]	Jun. 30, 2012 Utility [Member]	Mar. 31, 2012 Utility [Member]	Dec. 31, 2012 Utility [Member]	Dec. 31, 2011 Utility [Member]	Dec. 31, 2012 CPUC Investigations- Maximum Penalties Per Day [Member]	Dec. 31, 2011 San Bruno Explosion [Member]	Dec. 31, 2012 San Bruno Explosion [Member] Pacific Gas And Electric Company [Member]	Dec. 31, 2011 San Bruno Explosion [Member] Pacific Gas And Electric Company [Member]	Dec. 31, 2012 San Bruno Explosion [Member] San Mateo County Superior Court [Member] plaintiffs	Dec. 31, 2012 San Bruno Explosion [Member] Tort Lawsuits [Member] San Mateo County Superior Court [Member] lawsuits	Dec. 31, 2012 San Bruno Explosion [Member] Class Action Lawsuits [Member] San Mateo County Superior Court [Member] lawsuits
Loss Contingencies [Line Items]
Accrued legal liabilities			$ 34	$ 52	$ 146	$ 277		$ 214
Per violation penalty that may be imposed prior to the maximum statutory penalty increase, thousands															20
Penalty due to plat maps being misplaced	17
Per violation penalty that may be imposed subsequent to the maximum statutory penalty increase, thousands															50
Probable penalty amount			200
Additional costs accrued					80	155
Number of lawsuits																				140	2
Number of plaintiffs							140												450
Claim provision recorded																	80	0
Cumulative provision																	455
Estimated possible additional loss contingency liability																		145
Previously estimated maximum amount for third-party claims																		600
Insurance recoveries for cost incurred related to third-party claims	185								50	99	25	11		99
Estimated maximum amount for third-party claims for San Bruno																600
Utility liability insurance for damages					992
Utility liability insurance deductible					10
Number Of Distribution Maps Not Included In Survey Schedule	16
Utility Forecast On Penalties	477
Overcollection from customers from 1997 through 2010	100
Potential Equity Issuances To Fund Penalties	2,250
Capital Expenditures Recovery Allowed	1,000
Capital Expenditures Recovery Requested	1,400
Disallowed capital expenditure losses	353	36
Utility spent on capital expenditures 1996 to 2010	95
Utility spent on operations and maintenance 1996 to 2010	39
Spent fuel costs incurred through 2010	266
Estimated cost recovery on spent nuclear fuel storage proceeding every year	$ 25												$ 3,500	$ 2,300

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Earnings Per Share (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Shares Of Common Stock Outstanding For Calculating Diluted EPS) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Earnings Per Share [Abstract]
Income available for common shareholders	$ 816	$ 844
Weighted average common shares outstanding, basic	424	401	382
Add Incremental Shares From Assumed conversions:
Employee share-based compensation	1	1
Weighted average common shares outstanding, diluted	425	402	392
Net earnings per common share, basic	$ 1.92	$ 2.1	$ 2.86
Total earnings per common share, diluted	$ 1.92	$ 2.1	$ 2.82

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Related Party Agreements And Transactions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction [Line Items]
Current receivables	$ 19	$ 21
Current payables	17	13
Administrative Services Provided To PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility revenues from	7	6	7
Administrative Services Received From PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility expenses from	50	49	55
Utility Employee Benefit Due To PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility expenses from	$ 51	$ 33	$ 27

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Shares Of Common Stock Outstanding For Calculating Basic and Diluted EPS

	Year Ended December 31,
(in millions, except per share amounts)	2012		2011
Income available for common shareholders	$	816	$	844
Weighted average common shares outstanding, basic		424		401
Add incremental shares from assumed conversions:
Employee share-based compensation		1		1
Weighted average common share outstanding, diluted		425		402
Total earnings per common share, diluted	$	1.92	$	2.10

	Year Ended December 31, 2010
(in millions, except per share amounts)	Basic		Diluted
Income available for common shareholders	$	1,099	$	1,099
Less: distributed earnings to common shareholders		706		-
Undistributed earnings	$	393	$	1,099
Allocation of earnings to common shareholders
Distributed earnings to common shareholders	$	706	$	-
Undistributed earnings allocated to common shareholders		385		1,099
Add: Interest expense on convertible subordinated notes, net of tax		-		8
Total common shareholders earnings and assumed conversion	$	1,091	$	1,107
Weighted average common shares outstanding		382		382
Add incremental shares from assumed conversions:
Convertible subordinated notes		8		8
Employee share-based compensation		-		2
Weighted average common shares outstanding and participating securities		390		392
Net earnings per common share, basic
Distributed earnings, basic (1)	$	1.85	$	-
Undistributed earnings		1.01		2.82
Total	$	2.86	$	2.82

 ⁽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.

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Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 302	$ 708
Energy Recovery Bonds [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	(43)	(105)
Public Purpose Programs [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	(83)	97
Distribution Revenue Adjustment Mechanism [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	219	223
Utility Generation [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	117	241
Hazardous Substance [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	56	57
Gas Fixed Cost [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	44	16
Energy Procurement [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	77	(48)
Deparment Of Energy Settlement [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	(250)	0
Other Current Balancing Accounts [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 165	$ 227

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2012

Employee Benefit Plans

NOTE 12: EMPLOYEE BENEFIT PLANS

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees, as well as contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.  The trusts underlying certain of these plans are qualified trusts under the Internal Revenue Code of 1986, as amended (“Code”).  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.

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's minimum funding requirements related to its pension plans was zero.  

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 2012 and 2011:

Pension Benefits

(in millions)	2012		2011
Change in plan assets:
Fair value of plan assets at January 1	$	10,993	$	10,250
Actual return on plan assets		1,488		1,016
Company contributions		282		230
Benefits and expenses paid		(622)		(503)
Fair value of plan assets at December 31	$	12,141	$	10,993
Change in benefit obligation:
Projected benefit obligation at January 1	$	14,000	$	12,071
Service cost for benefits earned		396		320
Interest cost		658		660
Actuarial loss		1,099		1,450
Plan amendments		9		-
Transitional costs		1		2
Benefits and expenses paid		(622)		(503)
Projected benefit obligation at December 31 (1)	$	15,541	$	14,000
Funded status:
Current liability	$	(6)	$	(5)
Noncurrent liability		(3,394)		(3,002)
Accrued benefit cost at December 31	$	(3,400)	$	(3,007)
(1) PG&E Corporation's accumulated benefit obligation was $13,778 million and $12,285 million at December 31, 2012 and 2011, respectively

.

Other Benefits

(in millions)	2012		2011
Change in plan assets:
Fair value of plan assets at January 1	$	1,491	$	1,337
Actual return on plan assets		191		95
Company contributions		149		137
Plan participant contribution		55		52
Benefits and expenses paid		(128)		(130)
Fair value of plan assets at December 31	$	1,758	$	1,491
Change in benefit obligation:
Benefit obligation at January 1	$	1,885	$	1,755
Service cost for benefits earned		49		42
Interest cost		83		91
Actuarial loss		(23)		63
Plan amendments		5		-
Benefits paid		(119)		(130)
Federal subsidy on benefits paid		5		12
Plan participant contributions		55		52
Benefit obligation at December 31	$	1,940	$	1,885
Funded status:
Noncurrent liability	$	(181)	$	(394)
Accrued benefit cost at December 31	$	(181)	$	(394)

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

During 2012, the Utility's defined benefit pension plan was amended to include a new cash balance benefit formula.  Eligible employees hired after December 31, 2012 will participate in the cash balance benefit.  Eligible employees hired before January 1, 2013 will have a one-time opportunity to elect to participate in the cash balance benefit going forward, beginning on January 1, 2014 or to continue participating in the existing defined benefit plan.  As long as pension benefit costs continue to be recoverable through customer rates, PG&E Corporation and the Utility anticipate that this amendment will have no impact on net income.

Components of Net Periodic Benefit Cost

Net periodic benefit cost as reflected in PG&E Corporation's Consolidated Statements of Income for 2012, 2011, and 2010 was as follows:

Pension Benefits

(in millions)	2012		2011		2010
Service cost for benefits earned	$	396	$	320	$	279
Interest cost		658		660		645
Expected return on plan assets		(598)		(669)		(624)
Amortization of prior service cost		20		34		53
Amortization of unrecognized loss		123		50		44
Net periodic benefit cost		599		395		397
Less: transfer to regulatory account (1)		(301)		(139)		(233)
Total	$	298	$	256	$	164
(1) The Utility recorded $301 million, $139 million, and $233 million for the years ended December 31, 2012, 2011, and 2010, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates

Other Benefits

(in millions)	2012		2011		2010
Service cost for benefits earned	$	49	$	42	$	36
Interest cost		83		91		88
Expected return on plan assets		(77)		(82)		(74)
Amortization of transition obligation		24		26		26
Amortization of prior service cost		25		27		25
Amortization of unrecognized loss (gain)		6		4		3
Net periodic benefit cost	$	110	$	108	$	104

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.  

Components of Accumulated Other Comprehensive Income

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, 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.  

Regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between pension expense or income calculated in accordance with GAAP 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 costs for PG&E Corporation in 2013 are as follows:

Pension Benefit

(in millions)
Unrecognized prior service cost	$		20
Unrecognized net loss			110
Total	$		130
Other Benefits (in millions)
Unrecognized prior service cost		$		24
Unrecognized net loss				6
Total		$		30

There were no material differences between the estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation and the Utility.

Valuation Assumptions

The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic benefit costs.  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,
	2012		2011		2010		2012		2011		2010
Discount rate	3.98	%	4.66	%	5.42	%	3.75 - 4.08	%	4.41 - 4.77	%	5.11 - 5.56	%
Average rate of future
compensation increases	4.00	%	5.00	%	5.00	%	-		-		-
Expected return on plan assets	5.40	%	5.50	%	6.60	%	2.90 - 6.10	%	4.40 - 5.50	%	5.20 - 6.60	%

The assumed health care cost trend rate as of December 31, 2012 was 7.5%, 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:

	One-		One-
	Percentage-		Percentage-
	Point		Point
(in millions)	Increase		Decrease
Effect on postretirement benefit obligation	$	108	$	(111)
Effect on service and interest cost		8		(8)

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 5.4% compares to a ten-year actual return of 10.2%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 648 Aa-grade non-callable bonds at December 31, 2012.  This yield curve has discount rates that vary based on the duration of the obligations.  The estimated future cash flows for the pension benefits 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 in 2011 exceeded expectations due to a higher than expected return on fixed-income debt investments.   The actual return on plan assets in 2012 was in line with 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, credit, 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, 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 portfolios that include common stock and commingled funds across multiple industry sectors.  Real assets and absolute return investments are held to diversify the trust's holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets.  Real assets include commodities futures, global real estate investment trusts (“REITS”), global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios.

Over the last three years, target allocations for equity investments have generally declined in favor of longer-maturity fixed-income investments and real assets as a means of dampening future funded status volatility.  In 2012, equity index futures were added to maintain existing equity exposure while adding exposure to fixed-income securities.  Historically, the equity investment allocation was implemented through diversified U.S. equity, non-U.S. equity, and global portfolios.  In 2012, the U.S. equity and non-U.S. equity allocations were eliminated and became a combined global equity allocation.

In accordance with the pension plan's investment guidelines, derivative instruments such as equity-index futures contracts are used primarily to maintain equity and fixed income portfolio exposure consistent with the investment policy and to rebalance the fixed income/equity allocation of the pension's portfolio.  Foreign currency exchange contracts are also used to hedge a portion of the currency of the global equity investments.

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 designed 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 are as follows:

	Pension Benefits						Other Benefits
	2013		2012		2011		2013		2012		2011
Global equity securities	25	%	35	%	5	%	28	%	38	%	3	%
U.S. equity securities	-	%	-	%	26	%	-	%	-	%	28	%
Non-U.S. equity securities	-	%	-	%	14	%	-	%	-	%	15	%
Absolute return	5	%	5	%	5	%	4	%	4	%	4	%
Real assets	10	%	10	%	-	%	8	%	8	%	-	%
Extended fixed-income securities	3	%	3	%	-	%	-	%	-	%	-	%
Fixed-income securities	57	%	47	%	50	%	60	%	50	%	50	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

Fair Value Measurements

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2012 and 2011.  

	Fair Value Measurements
	At December 31,
	2012								2011
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Benefits:
Money market investments	$	112	$	-	$	-	$	112	$	51	$	-	$	-	$	51
U.S. equity securities		-		-		-		-		273		2,161		-		2,434
Non-U.S. equity securities		-		-		-		-		131		1,363		-		1,494
Global equity securities		402		3,017		-		3,419		-		197		-		197
Absolute return		-		-		513		513		-		-		487		487
Real assets		525		-		285		810		522		-		65		587
Fixed-income securities:
U.S. government		1,576		139		-		1,715		1,224		172		-		1,396
Corporate		3		4,275		611		4,889		2		3,083		585		3,670
Other		-		576		-		576		1		688		-		689
Total	$	2,618	$	8,007	$	1,409	$	12,034	$	2,204	$	7,664	$	1,137	$	11,005
Other Benefits:
Money market investments	$	77	$	-	$	-	$	77	$	48	$	-	$	-	$	48
U.S. equity securities		-		-		-		-		86		222		-		308
Non-U.S. equity securities		-		-		-		-		79		108		-		187
Global equity securities		118		397		-		515		-		19		-		19
Absolute return		-		-		49		49		-		-		47		47
Real assets		68		-		28		96		31		-		6		37
Fixed-income securities:
U.S. government		148		5		-		153		151		-		-		151
Corporate		9		795		1		805		-		681		1		682
Other		-		38		-		38		1		44		-		45
Total	$	420	$	1,235	$	78	$	1,733	$	396	$	1,074	$	54	$	1,524
Total plan assets at fair value							$	13,767							$	12,529

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $132 million and other net liabilities of $45 million at December 31, 2012 and 2011, respectively.  These net assets and net liabilities were comprised primarily of cash, accounts receivable, accounts payable, and deferred taxes.

                                          Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above.  All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days.

Money Market Investments

Money market investments consist primarily of commingled funds of U.S. government 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.

Equity Securities

The global equity categories include equity investments in common stock and equity-index futures, and commingled funds comprised of equity across multiple industries and regions of the world.  Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets.  These equity investments are generally valued based on unadjusted prices in active markets for identical securities.  Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets.  Collateral posted related to these futures consist of money market investments that are considered Level 1 assets.  Commingled funds are valued using a net asset value per share and 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 using a net asset value per share 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.

Real Assets

The real asset category includes portfolios of commodities, commodities futures, global REITS, global listed infrastructure equities, and private real estate funds.  The commodities, commodities futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets.  Collateral posted related to the commodities futures consist of money market investments that are considered Level 1 assets.  Private real estate funds are valued using a net asset value per share derived using appraisals, pricing models, and valuation inputs that are unobservable and 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 derivative instruments.  These securities are classified as Level 2 assets.  Corporate fixed-income also includes commingled funds that are valued using a net asset value per share and are comprised of corporate debt instruments.  Commingled funds are considered Level 2 assets.  Corporate fixed income also includes insurance contracts for deferred annuities.  These investments are valued using a net asset value per share using pricing models and valuation inputs that are unobservable and are considered Level 3 assets.  

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 and are considered Level 2 assets.  Other fixed-income also includes municipal bonds and index futures.  Collateral posted related to the index futures consist of money market investments that are considered Level 1 assets.  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.

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.  As shown in the table below, transfers out of Level 3 represent assets that were previously classified as Level 3 for which the lowest significant input became observable during the period.  No significant transfers between Levels 1 and 2 occurred in the years ended December 31, 2012 and 2011.

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, 2012 and 2011:

	Pension Benefits
	Absolute		Corporate		Other
(in millions)	Return		Fixed-Income		Fixed-Income		Real Assets		Total
Balance as of January 1, 2011	$	494	$	549	$	120	$	-	$	1,163
Actual return on plan assets:
Relating to assets still held at the reporting date		5		57		(2)		-		60
Relating to assets sold during the period		2		-		1		-		3
Purchases, issuances, sales, and settlements
Purchases		-		14		2		65		81
Settlements		(14)		(35)		(58)		-		(107)
Transfers out of Level 3		-		-		(63)		-		(63)
Balance as of December 31, 2011	$	487	$	585	$	-	$	65	$	1,137
Actual return on plan  assets:
Relating to assets still held at the reporting date		26		28		-		12		66
Relating to assets sold during the period		-		(1)		-		-		(1)
Purchases, issuances, sales, and settlements
Purchases		-		12		-		208		220
Settlements		-		(13)		-		-		(13)
Balance as of December 31, 2012	$	513	$	611	$	-	$	285	$	1,409

	Other Benefits
	Absolute		Corporate		Other
(in millions)	Return		Fixed-Income		Fixed-Income		Real Assets		Total
Balance as of January 1, 2011	$	47	$	129	$	10		-	$	186
Actual return on plan assets:
Relating to assets still held at the reporting date		1		16		-		-		17
Relating to assets sold during the period		-		(2)		-		-		(2)
Purchases, issuances, sales, and settlements
Purchases		-		34		-		6		40
Settlements		(1)		(30)		(5)		-		(36)
Transfers out of Level 3		-		(146)		(5)		-		(151)
Balance as of December 31, 2011	$	47	$	1	$	-	$	6	$	54
Actual return on plan  assets:
Relating to assets still held at the reporting date		2		-		-		1		3
Relating to assets sold during the period		-		-		-		-		-
Purchases, issuances, sales, and settlements
Purchases		-		1		-		21		22
Settlements		-		(1)		-		-		(1)
Balance as of December 31, 2012	$	49	$	1	$	-	$	28	$	78

      There were no transfers out of Level 3 in 2012.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $282 million to the pension benefit plans and $149 million to the other benefit plans in 2012.  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 2012.  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 $327 million and $109 million to the pension plan and other postretirement benefit plans, respectively, for 2013.

Benefits Payments and Receipts

As of December 31, 2012, the estimated benefits PG&E Corporation is expected to pay and federal subsidies it is estimated to receive in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter for PG&E Corporation, are as follows:

(in millions)	Pension		Other		Federal Subsidy
2013	$	581	$	108	$	(6)
2014		618		112		(7)
2015		656		115		(7)
2016		695		119		(8)
2017		732		124		(8)
2018 - 2022		4,172		662		(42)

There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above.  There were no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.

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,
2012	$	67
2011		65
2010		56

There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.

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Schedule I - Condensed Financial Information Of Parent

12 Months Ended

Dec. 31, 2012

Schedule I - Condensed Financial Information Of Parent

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

 (in millions, except per share amounts)

	Year Ended December 31,
	2012	2011	2010
Administrative service revenue	$ 43	$ 44	$ 53
Operating expenses	(41	)	(55	)
Interest income	1	1	1
Interest expense	(22	)	(35	)
Other income (expense)	(39	)	4
Equity in earnings of subsidiaries	817	852	1,105
Income before income taxes	759	814	1,073
Income tax benefit	57	30	26
Net Income	816	$ 844	$ 1,099
Other Comprehensive Income
Pension and other postretirement benefit plans (net of income tax of $72, $9, $25 in 2012, 2011, and 2010, respectively)	108	(11	)
Other (net of income tax of $3 in 2012)	4	-	-
Total other comprehensive income (loss)	112	(11	)
Comprehensive Income	$ 928	$ 833	$ 1,057
Weighted average common shares outstanding, basic	424	401	382
Weighted average common shares outstanding, diluted	425	402	392
Net earnings per common share, basic	$ 1.92	$ 2.10	$ 2.86
Net earnings per common share, diluted	$ 1.92	$ 2.10	$ 2.82

PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS.  In addition, during 2010, PG&E Corporation applied the “if-converted” method to reflect the impact of the Convertible Subordinated Notes to the extent it was dilutive when compared to basic EPS.

PG&E CORPORATION

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

CONDENSED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2012	2011
ASSETS
Current Assets
Cash and cash equivalents	$ 207	$ 209
Advances to affiliates	26	18
Income taxes receivable	33	8
Deferred income taxes	-	4
Total current assets	266	239
Noncurrent Assets
Equipment	1	14
Accumulated depreciation	(1	)
Net equipment	-	-
Investments in subsidiaries	13,387	12,378
Other investments	102	94
Income taxes receivable	5	2
Deferred income taxes	178	143
Other	1	2
Total noncurrent assets	13,673	12,619
Total Assets	$ 13,939	$ 12,858
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$ 120	$ -
Accounts payable - other	48	21
Income taxes payable	-	57
Other	221	208
Total current liabilities	389	286
Noncurrent Liabilities
Longdebt	349	349
Other	127	122
Total noncurrent liabilities	476	471
Common Shareholders' Equity
Common stock	8,428	7,602
Reinvested earnings	4,747	4,712
Accumulated other comprehensive loss	(101	)
Total common shareholders' equity	13,074	12,101
Total Liabilities and Shareholders' Equity	$ 13,939	$ 12,858

PG&E CORPORATION

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

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

		Year Ended December 31,
		2012			2011			2010
Cash Flows from Operating Activities:
Net income		$	816		$	844		$	1,099
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization			51			36			38
Equity in earnings of subsidiaries			(817	)		(852	)		(1,105	)
Deferred income taxes and tax credits, net			(31	)		(26	)		19
Noncurrent income taxes receivable/payable			(6	)		(47	)		34
Current income taxes receivable/payable			(82	)		49			(1	)
Other			20			(80	)		(50	)
Net cash provided by (used in) operating activities			(49)			(76	)		34
Cash Flows From Investing Activities:
Investment in subsidiaries			(1,023	)		(759	)		(347	)
Dividends received from subsidiaries (1)			716			716			716
Proceeds from tax equity investments			228			129			7
Other			-			-			(4	)
Net cash provided by (used in) investing activities			(79)			86			372
Cash Flows From Financing Activities:
Borrowings under revolving credit facilities			120			150			90
Repayments under revolving credit facilities			-			(150	)		(90	)
Common stock issued			751			662			303
Common stock dividends paid (2)			(746	)		(704	)		(662	)
Other			1			1			-
Net cash provided by (used in) financing activities			126			(41	)		(359	)
Net change in cash and cash equivalents			(2	)		(31	)		47
Cash and cash equivalents at January 1			209			240			193
Cash and cash equivalents at December 31		$	207		$	209		$	240
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized		$	(20	)	$	(20	)	$	(20	)
Income taxes, net			(60	)		8			36
Supplemental disclosures of noncash investing and financing
activities
Noncash common stock issuances		$	22		$	24		$	265
Common stock dividends declared but not yet paid			196			188			183
(1	)
(2	)
	On January 15, April 15, July 15, October 15, 2011, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
	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.

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Commitments And Contingencies (Third-Party Power Purchases) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Long-term Purchase Commitment [Line Items]
2013	$ 3,094
2014	3,434
2015	3,414
2016	3,298
2017	3,140
Thereafter	36,518
Total	52,898
QF Energy Payments [Member]
Long-term Purchase Commitment [Line Items]
2013	892
2014	914
2015	727
2016	618
2017	490
Thereafter	2,238
Total	5,879
Renewable (Other Than QF) Energy [Member]
Long-term Purchase Commitment [Line Items]
2013	1,356
2014	1,843
2015	2,038
2016	2,054
2017	2,053
Thereafter	30,958
Total	40,302
Other, Energy Payments [Member]
Long-term Purchase Commitment [Line Items]
2013	846
2014	677
2015	649
2016	626
2017	597
Thereafter	3,322
Total	$ 6,717

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Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 6,809	$ 6,506
Pension Benefit [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	3,275	2,899
Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,627	1,444
Utility Retained Generation [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	552	613
Environmental Compliance Costs [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	604	520
Price Risk Management [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	210	339
Electromechanical meters [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	194	247
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	141	163
Other Long-Term Regulatory Assets [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 206	$ 281

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Commitments And Contingencies (Environmental Remediation Liability Disclosure) (Details) (Pacific Gas And Electric Company [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Long-term Purchase Commitment [Line Items]
Balance at December 31, 2011	$ 785
Transfer to regulatory account for recovery	150
Amounts not recoverable from customers	150
Less: Payments	(175)
Balance at December 31, 2012	910
Remediation Costs For Generation And Other Facilities And For Third-Party Disposal Sites [Member]
Long-term Purchase Commitment [Line Items]
Balance at December 31, 2012	$ 239

XML

Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments And Contingencies [Abstract]

Schedule Of Costs Incurred Attributable To Each Category Of Power Purchase Agreements

(in millions)	2012		2011		2010
Qualifying facilities(1)	$	779	$	1,069	$	1,164
Renewable energy contracts		815		622		573
Other power purchase agreements		661		690		657

 ⁽¹⁾ Costs incurred include $286, $297, and $321 attributable to renewable energy contracts with qualifying facilities at December 31, 2012, 2011 and 2010, respectively.

Schedule Of Undiscounted Future Expected Power Purchase Agreement Payments

				Renewable
(in millions)	Qualifying Facility		(Other than QF)		Other		Total Payments
2013	$	892	$	1,356	$	846	$	3,094
2014		914		1,843		677		3,434
2015		727		2,038		649		3,414
2016		618		2,054		626		3,298
2017		490		2,053		597		3,140
Thereafter		2,238		30,958		3,322		36,518
Total	$	5,879	$	40,302	$	6,717	$	52,898

Schedule Of Fixed Capacity Payments Due Under The QF Contracts Discount

(in millions)
2013	$	35
2014		27
2015		24
2016		22
2017		18
Thereafter		20
Total fixed capacity payments		146
Less: amount representing interest		21
Present value of fixed capacity payments	$	125

Undiscounted Obligations For Natural Gas Purchases, Gas Transportation Services, And Gas Storage

(in millions)
2013	$	707
2014		208
2015		192
2016		152
2017		108
Thereafter		865
Total	$	2,232

Undiscounted Obligations Under Nuclear Fuel Agreements

(in millions)
2013	$	113
2014		128
2015		194
2016		147
2017		148
Thereafter		878
Total	$	1,608

Future Minimum Payments Of Operating Leases

(in millions)
2013	$	42
2014		37
2015		32
2016		31
2017		24
Thereafter		206
Total	$	372

Change In Accruals Related To Third-Party Claims

(in millions)
Balance at January 1, 2010	$	-
Loss accrued		220
Less: Payments		(6	)
Balance at December 31, 2010		214
Additional loss accrued		155
Less: Payments		(92	)
Balance at December 31, 2011		277
Additional loss accrued		80
Less: Payments		(211	)
Balance at December 31, 2012	$	146

Environmental Remediation Liability Disclosure

(in millions)
Balance at December 31, 2011	$	785
Additional remediation costs accrued:
Transfer to regulatory account for  recovery		150
Amounts not recoverable from customers		150
Less: Payments		(175)
Balance at December 31, 2012	$	910

	Balance at December 31,
(in millions)	2012		2011
Utility-owned natural gas compressor site near Hinkley, California (1)	$	226	$	149
Utility-owned natural gas compressor site near Topock, Arizona (1)		239		218
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites		158		133
Former manufatured gas plant sites owned by the Utility or third parties		181		154
Fossil fuel-fired generation facilities formerly owned by the Utility		87		81
Decommissioning fossil fuel-fired generation facilities and sites		19		50
Total environmental remediation liability	$	910	$	785
(1) See “Natural Gas Compressor Site” below.

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Quarterly Consolidated Financial Data (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended			3 Months Ended				12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Utility [Member]	Sep. 30, 2012 Utility [Member]	Jun. 30, 2012 Utility [Member]	Mar. 31, 2012 Utility [Member]	Dec. 31, 2011 Utility [Member]
Loss accrued						$ 80
Insurance recoveries for cost incurred related to third-party claims	185			50	99	25	11	99
Disallowed capital expenditures	$ 353	$ 0	$ 36	$ 353

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 401	$ 513
Restricted cash ($0 and $51 related to energy recovery bonds at December 31, 2012 and 2011, respectively)	330	380
Accounts receivable
Customers (net of allowance for doubtful accounts of $87 and $81 at December 31, 2012 and 2011)	937	992
Accrued unbilled revenue	761	763
Regulatory balancing accounts	936	1,082
Other	365	839
Regulatory assets ($0 and $336 related to energy recovery bonds at December 31, 2012 and 2011, respectively)	564	1,090
Inventories
Gas stored underground and fuel oil	135	159
Materials and supplies	309	261
Income taxes receivable	211	183
Other	172	218
Total current assets	5,121	6,480
Property, Plant, and Equipment
Electric	39,701	35,851
Gas	12,571	11,931
Construction work in progress	1,894	1,770
Other	1	15
Total property, plant, and equipment	54,167	49,567
Accumulated depreciation	(16,644)	(15,912)
Net property, plant, and equipment	37,523	33,655
Other Noncurrent Assets
Regulatory assets	6,809	6,506
Nuclear decommissioning trusts	2,161	2,041
Income taxes receivable	176	386
Other	659	682
Total other noncurrent assets	9,805	9,615
TOTAL ASSETS	52,449	49,750
Current Liabilities
Short-term borrowings	492	1,647
Long-term debt, classified as current	400	50
Energy recovery bonds, classified as current	0	423
Accounts payable
Trade creditors	1,241	1,177
Disputed claims and customer refunds	157	673
Regulatory balancing accounts	634	374
Other	444	420
Interest payable	870	843
Income taxes payable	6	110
Deferred income taxes	0	196
Other	2,012	1,836
Total current liabilities	6,256	7,749
Noncurrent Liabilities
Long-term debt	12,517	11,766
Regulatory liabilities	5,088	4,733
Pension and other postretirement benefits	3,575	3,396
Asset retirement obligations	2,919	1,609
Deferred income taxes	6,748	6,008
Other	2,020	2,136
Total noncurrent liabilities	32,867	29,648
Commitments and Contingencies (Note 15)
Shareholders' Equity
Preferred stock	0	0
Common stock	8,428	7,602
Reinvested earnings	4,747	4,712
Accumulated other comprehensive loss	(101)	(213)
Total shareholders' equity	13,074	12,101
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	13,326	12,353
TOTAL LIABILITIES AND EQUITY	52,449	49,750
Pacific Gas And Electric Company [Member]
Current Assets
Cash and cash equivalents	194	304
Restricted cash ($0 and $51 related to energy recovery bonds at December 31, 2012 and 2011, respectively)	330	380
Accounts receivable
Customers (net of allowance for doubtful accounts of $87 and $81 at December 31, 2012 and 2011)	937	992
Accrued unbilled revenue	761	763
Regulatory balancing accounts	936	1,082
Other	366	840
Regulatory assets ($0 and $336 related to energy recovery bonds at December 31, 2012 and 2011, respectively)	564	1,090
Inventories
Gas stored underground and fuel oil	135	159
Materials and supplies	309	261
Income taxes receivable	186	242
Other	160	213
Total current assets	4,878	6,326
Property, Plant, and Equipment
Electric	39,701	35,851
Gas	12,571	11,931
Construction work in progress	1,894	1,770
Total property, plant, and equipment	54,166	49,552
Accumulated depreciation	(16,643)	(15,898)
Net property, plant, and equipment	37,523	33,654
Other Noncurrent Assets
Regulatory assets	6,809	6,506
Nuclear decommissioning trusts	2,161	2,041
Income taxes receivable	171	384
Other	381	331
Total other noncurrent assets	9,522	9,262
TOTAL ASSETS	51,923	49,242
Current Liabilities
Short-term borrowings	372	1,647
Long-term debt, classified as current	400	50
Energy recovery bonds, classified as current	0	423
Accounts payable
Trade creditors	1,241	1,177
Disputed claims and customer refunds	157	673
Regulatory balancing accounts	634	374
Other	419	417
Interest payable	865	838
Income taxes payable	12	118
Deferred income taxes	0	199
Other	1,794	1,628
Total current liabilities	5,894	7,544
Noncurrent Liabilities
Long-term debt	12,167	11,417
Regulatory liabilities	5,088	4,733
Pension and other postretirement benefits	3,497	3,325
Asset retirement obligations	2,919	1,609
Deferred income taxes	6,939	6,160
Other	1,959	2,070
Total noncurrent liabilities	32,569	29,314
Commitments and Contingencies (Note 15)
Shareholders' Equity
Preferred stock	258	258
Common stock	1,322	1,322
Additional paid-in capital	4,682	3,796
Reinvested earnings	7,291	7,210
Accumulated other comprehensive loss	(93)	(202)
Total shareholders' equity	13,460	12,384
TOTAL LIABILITIES AND EQUITY	$ 51,923	$ 49,242

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Employee Benefit Plans (Schedule Of Level 3 Reconciliation) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	$ 13,767	$ 12,529
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	1,733	1,524
Other Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	420	396
Other Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	1,235	1,074
Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	54	186
Relating to assets still held at the reporting date	3	17
Relating to assets sold during the period	0	(2)
Purchases	22	40
Settlements	(1)	(36)
Transfers out of Level 3	0	(151)
Balance as of December 31	78	54
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	12,034	11,005
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	2,618	2,204
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	8,007	7,664
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	1,137	1,163
Relating to assets still held at the reporting date	66	60
Relating to assets sold during the period	(1)	3
Purchases	220	81
Settlements	(13)	(107)
Transfers out of Level 3	0	(63)
Balance as of December 31	1,409	1,137
Real Estate [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	6	0
Relating to assets still held at the reporting date	1	0
Relating to assets sold during the period	0	0
Purchases	21	6
Settlements	0	0
Transfers out of Level 3	0	0
Balance as of December 31	28	6
Real Estate [Member] | Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	65	0
Relating to assets still held at the reporting date	12	0
Relating to assets sold during the period	0	0
Purchases	208	65
Settlements	0	0
Transfers out of Level 3	0	0
Balance as of December 31	285	65
Absolute Return [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	47	47
Relating to assets still held at the reporting date	2	1
Relating to assets sold during the period	0	0
Purchases	0	0
Settlements	0	(1)
Transfers out of Level 3	0	0
Balance as of December 31	49	47
Absolute Return [Member] | Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	487	494
Relating to assets still held at the reporting date	26	5
Relating to assets sold during the period	0	2
Purchases	0	0
Settlements	0	(14)
Transfers out of Level 3	0	0
Balance as of December 31	513	487
Corporate Fixed Income Securities [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	1	129
Relating to assets still held at the reporting date	0	16
Relating to assets sold during the period	0	(2)
Purchases	1	34
Settlements	(1)	(30)
Transfers out of Level 3	0	(146)
Balance as of December 31	1	1
Corporate Fixed Income Securities [Member] | Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	585	549
Relating to assets still held at the reporting date	28	57
Relating to assets sold during the period	(1)	0
Purchases	12	14
Settlements	(13)	(35)
Transfers out of Level 3	0	0
Balance as of December 31	611	585
Other Fixed Income [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	0	10
Relating to assets still held at the reporting date	0	0
Relating to assets sold during the period	0	0
Purchases	0	0
Settlements	0	(5)
Transfers out of Level 3	0	(5)
Balance as of December 31	0	0
Other Fixed Income [Member] | Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	0	120
Relating to assets still held at the reporting date	0	(2)
Relating to assets sold during the period	0	1
Purchases	0	2
Settlements	0	(58)
Transfers out of Level 3	0	(63)
Balance as of December 31	$ 0	$ 0

XML

Organization And Basis Of Presentation

12 Months Ended

Dec. 31, 2012

Organization And Basis Of Presentation

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company that conducts its business 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 primarily regulated 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 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.  PG&E Corporation and the Utility operate in one segment.

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, legal and regulatory contingencies, environmental remediation liabilities, asset retirement obligations (“ARO”), and pension and other postretirement benefit plans obligations.  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.  

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Common Stock And Share-Based Compensation (Long-Term Incentive Plan) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issued for LTIP, maximum	12,000,000
Shares available for LTIP award	4,548,119
Total Compensation Expense (pre-tax)	$ 57	$ 26	$ 56
Total Compensation Expense (after-tax)	34	16	33
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total Compensation Expense (pre-tax)	31	22	9
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total Compensation Expense (pre-tax)	0	1	14
Performance Shares, Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total Compensation Expense (pre-tax)	26	16	11
Performance Shares, Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total Compensation Expense (pre-tax)	$ 0	$ (13)	$ 22

XML

Employee Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Less: Transfer To Regulatory Account	$ 301		$ 139		$ 233
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	49		42		36
Interest cost	83		91		88
Expected return on plan assets	(77)		(82)		(74)
Amortization of transition obligation	24		26		26
Amortization of prior service cost	25		27		25
Amortization of unrecognized loss	6		4		3
Net periodic benefit cost	110		108		104
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	396		320		279
Interest cost	658		660		645
Expected return on plan assets	(598)		(669)		(624)
Amortization of prior service cost	20		34		53
Amortization of unrecognized loss	123		50		44
Net periodic benefit cost	599		395		397
Less: Transfer To Regulatory Account	(301)	[1]	(139)	[1]	(233)	[1]
Total	$ 298		$ 256		$ 164

[1] The Utility recorded $301 million, $139 million, and $233 million for the years ended December 31, 2012, 2011, and 2010, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates

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Commitments And Contingencies (Environmental Remediation Liability Composed) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Utility-owned natural gas compressor site near Hinkley, California	$ 226	[1]	$ 149	[1]
Utility-owned natural gas compressor site near Topock, Arizona	239	[1]	218	[1]
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites	158		133
Former MGP sites owned by the Utility or third parties	181		154
Fossil fuel-fired generation facilities formerly owned by the Utility	87		81
Decommissioning fossil fuel-fired generation facilities and sites	19		50
Total environmental remediation liability	$ 910		$ 785

[1] See "Natural Gas Compressr Site" below.

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Income Taxes (Schedule Of Change In Unrecognized Tax Benefits) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pacific Gas And Electric Company [Member]
Balance at beginning of year	$ 506	$ 714	$ 673
Additions for tax position taken during a prior year	32	2	27
Reductions for tax position taken during a prior year	(13)	(198)	(20)
Additions for tax position taken during the current year	67	3	89
Settlements	(11)	(15)	(55)
Balance at end of year	581	506	714
Utility [Member]
Balance at beginning of year	503	712	652
Additions for tax position taken during a prior year	26	2	27
Reductions for tax position taken during a prior year	(10)	(196)	0
Additions for tax position taken during the current year	67	0	87
Settlements	(11)	(15)	(54)
Balance at end of year	$ 575	$ 503	$ 712

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Schedule II - Consolidated Valuation And Qualifying Accounts

12 Months Ended

Dec. 31, 2012

Schedule II - Consolidated Valuation And Qualifying Accounts

PG&E Corporation

SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2012, 2011, and 2010

(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:
2012:
Allowance for uncollectible accounts(1)	$ 81	$ 66	$ -	$ 60	$ 87
2011:
Allowance for uncollectible accounts(1)	$ 81	$ 60	$ -	$ 60	$ 81
2010:
Allowance for uncollectible accounts(1)	$ 68	$ 56	$ -	$ 43	$ 81
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

Pacific Gas and Electric Company

SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2012, 2011, and 2010

(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:
2012:
Allowance for uncollectible accounts(1)	$ 81	$ 66	$ -	$ 60	$ 87
2011:
Allowance for uncollectible accounts(1)	$ 81	$ 60	$ -	$ 60	$ 81
2010:
Allowance for uncollectible accounts(1)	$ 68	$ 56	$ -	$ 43	$ 81
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

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Fair Value Measurements (Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) (USD $)	Dec. 31, 2012		Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value	$ 240,000,000		$ 188,000,000
Estimate Of Fair Value Fair Value Disclosure [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	209,000,000		206,000,000
Total assets	3,030,000,000		2,881,000,000
Total liabilities	311,000,000		414,000,000
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	209,000,000		206,000,000
Total assets	2,241,000,000		2,127,000,000
Total liabilities	163,000,000		442,000,000
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	708,000,000		680,000,000
Total liabilities	153,000,000		302,000,000
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	81,000,000		69,000,000
Total liabilities	160,000,000		143,000,000
Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	0	[1]	5,000,000	[1]
Total liabilities	(165,000,000)		(473,000,000)
Nuclear Decommissioning Trusts [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	21,000,000		24,000,000
U.S. equity securities	940,000,000		841,000,000
Non-U.S. equity securities	379,000,000		323,000,000
U.S. government and agency securities	681,000,000		720,000,000
Total assets	2,021,000,000	[2]	1,908,000,000	[3]
Nuclear Decommissioning Trusts [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U.S. equity securities	9,000,000		8,000,000
U.S. government and agency securities	139,000,000		156,000,000
Municipal securities	59,000,000		58,000,000
Other fixed-income securities	173,000,000		99,000,000
Total assets	380,000,000	[2]	321,000,000	[3]
Nuclear Decommissioning Trusts [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	21,000,000		24,000,000
U.S. equity securities	949,000,000		849,000,000
Non-U.S. equity securities	379,000,000		323,000,000
U.S. government and agency securities	820,000,000		876,000,000
Municipal securities	59,000,000		58,000,000
Other fixed-income securities	173,000,000		99,000,000
Total assets	2,401,000,000	[2]	2,229,000,000	[3]
Price Risk Management Instruments [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	1,000,000
Electric	1,000,000
Electric	155,000,000		411,000,000
Gas	8,000,000		31,000,000
Price Risk Management Instruments [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	65,000,000		98,000,000
Electric	60,000,000		92,000,000
Gas	5,000,000		6,000,000
Electric	144,000,000		289,000,000
Gas	9,000,000		13,000,000
Price Risk Management Instruments [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	81,000,000		69,000,000
Electric	80,000,000		69,000,000
Gas	1,000,000
Electric	160,000,000		143,000,000
Price Risk Management Instruments [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	0	[1]	5,000,000	[1]
Electric	6,000,000	[1]	8,000,000	[1]
Gas	(6,000,000)	[1]	(3,000,000)	[1]
Electric	(156,000,000)		(441,000,000)	[1]
Gas	(9,000,000)	[1]	(32,000,000)	[1]
Price Risk Management Instruments [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	147,000,000		172,000,000
Electric	147,000,000		169,000,000
Gas	0		3,000,000
Electric	303,000,000		402,000,000
Gas	8,000,000		12,000,000
Rabbi Trusts [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other fixed-income securities	30,000,000		25,000,000
Life insurance contracts	72,000,000		67,000,000
Total assets	102,000,000		92,000,000
Rabbi Trusts [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other fixed-income securities	30,000,000		25,000,000
Life insurance contracts	72,000,000		67,000,000
Total assets	102,000,000		92,000,000
Long-Term Disability Trust [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	10,000,000		13,000,000
U.S. equity securities	0		0
Total assets	10,000,000		13,000,000
Long-Term Disability Trust [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U.S. equity securities	14,000,000		15,000,000
Non-U.S. equity securities	11,000,000		9,000,000
Fixed-income securities	136,000,000		145,000,000
Total assets	161,000,000		169,000,000
Long-Term Disability Trust [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	10,000,000		13,000,000
U.S. equity securities	14,000,000		15,000,000
Non-U.S. equity securities	11,000,000		9,000,000
Fixed-income securities	136,000,000		145,000,000
Total assets	$ 171,000,000		$ 182,000,000

[1] Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

[2] Excludes $240 million at December 31, 2012 primarily related to deferred taxes on appreciation of investment value.

[3] Excludes $188 million at December 31, 2011 primarily related to deferred taxes on appreciation of investment value.

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2012

Defined Benefit Plan Disclosure [Line Items]

Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status

(in millions) Pension Benefits	2012		2011
Change in plan assets:
Fair value of plan assets at January 1	$	10,993	$	10,250
Actual return on plan assets		1,488		1,016
Company contributions		282		230
Benefits and expenses paid		(622)		(503)
Fair value of plan assets at December 31	$	12,141	$	10,993
Change in benefit obligation:
Projected benefit obligation at January 1	$	14,000	$	12,071
Service cost for benefits earned		396		320
Interest cost		658		660
Actuarial loss		1,099		1,450
Plan amendments		9		-
Transitional costs		1		2
Benefits and expenses paid		(622)		(503)
Projected benefit obligation at December 31 (1)	$	15,541	$	14,000
Funded status:
Current liability	$	(6)	$	(5)
Noncurrent liability		(3,394)		(3,002)
Accrued benefit cost at December 31	$	(3,400)	$	(3,007)

 ⁽¹⁾ PG&E Corporation's accumulated benefit obligation was $13,778 million and $12,285 million at December 31, 2012 and 2011, respectively.

(in millions) Other Benefits	2012		2011
Change in plan assets:
Fair value of plan assets at January 1	$	1,491	$	1,337
Actual return on plan assets		191		95
Company contributions		149		137
Plan participant contribution		55		52
Benefits and expenses paid		(128)		(130)
Fair value of plan assets at December 31	$	1,758	$	1,491
Change in benefit obligation:
Benefit obligation at January 1	$	1,885	$	1,755
Service cost for benefits earned		49		42
Interest cost		83		91
Actuarial loss		(23)		63
Plan amendments		5		-
Benefits paid		(119)		(130)
Federal subsidy on benefits paid		5		12
Plan participant contributions		55		52
Benefit obligation at December 31	$	1,940	$	1,885
Funded status:
Noncurrent liability	$	(181)	$	(394)
Accrued benefit cost at December 31	$	(181)	$	(394)

Components Of Net Periodic Benefit Cost

(in millions) Pension Benefits	2012		2011		2010
Service cost for benefits earned	$	396	$	320	$	279
Interest cost		658		660		645
Expected return on plan assets		(598)		(669)		(624)
Amortization of prior service cost		20		34		53
Amortization of unrecognized loss		123		50		44
Net periodic benefit cost		599		395		397
Less: transfer to regulatory account (1)		(301)		(139)		(233)
Total	$	298	$	256	$	164

 ⁽¹⁾ The Utility recorded $301 million, $139 million, and $233 million for the years ended December 31, 2012, 2011, and 2010, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates

(in millions) Other Benefits	2012		2011		2010
Service cost for benefits earned	$	49	$	42	$	36
Interest cost		83		91		88
Expected return on plan assets		(77)		(82)		(74)
Amortization of transition obligation		24		26		26
Amortization of prior service cost		25		27		25
Amortization of unrecognized loss (gain)		6		4		3
Net periodic benefit cost	$	110	$	108	$	104

Estimated Amortized Net Periodic Benefit For 2012

(in millions) Pension Benefit
Unrecognized prior service cost	$		20
Unrecognized net loss			110
Total	$		130
(in millions) Other Benefits
Unrecognized prior service cost		$		24
Unrecognized net loss				6
Total		$		30

Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost

	Pension Benefits						Other Benefits
	December 31,						December 31,
	2012		2011		2010		2012		2011		2010
Discount rate	3.98	%	4.66	%	5.42	%	3.75 - 4.08	%	4.41 - 4.77	%	5.11 - 5.56	%
Average rate of future
compensation increases	4.00	%	5.00	%	5.00	%	-		-		-
Expected return on plan assets	5.40	%	5.50	%	6.60	%	2.90 - 6.10	%	4.40 - 5.50	%	5.20 - 6.60	%

Schedule Of Assumed Health Care Cost Trend

	One-		One-
	Percentage-		Percentage-
	Point		Point
(in millions)	Increase		Decrease
Effect on postretirement benefit obligation	$	108	$	(111)
Effect on service and interest cost		8		(8)

Target Asset Allocation Percentages

	Pension Benefits						Other Benefits
	2013		2012		2011		2013		2012		2011
Global equity securities	25	%	35	%	5	%	28	%	38	%	3	%
U.S. equity securities	-	%	-	%	26	%	-	%	-	%	28	%
Non-U.S. equity securities	-	%	-	%	14	%	-	%	-	%	15	%
Absolute return	5	%	5	%	5	%	4	%	4	%	4	%
Real assets	10	%	10	%	-	%	8	%	8	%	-	%
Extended fixed-income securities	3	%	3	%	-	%	-	%	-	%	-	%
Fixed-income securities	57	%	47	%	50	%	60	%	50	%	50	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

Schedule Of Changes In Fair Value Of Plan Assets

	Fair Value Measurements
	At December 31,
	2012								2011
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Benefits:
Money market investments	$	112	$	-	$	-	$	112	$	51	$	-	$	-	$	51
U.S. equity securities		-		-		-		-		273		2,161		-		2,434
Non-U.S. equity securities		-		-		-		-		131		1,363		-		1,494
Global equity securities		402		3,017		-		3,419		-		197		-		197
Absolute return		-		-		513		513		-		-		487		487
Real assets		525		-		285		810		522		-		65		587
Fixed-income securities:
U.S. government		1,576		139		-		1,715		1,224		172		-		1,396
Corporate		3		4,275		611		4,889		2		3,083		585		3,670
Other		-		576		-		576		1		688		-		689
Total	$	2,618	$	8,007	$	1,409	$	12,034	$	2,204	$	7,664	$	1,137	$	11,005
Other Benefits:
Money market investments	$	77	$	-	$	-	$	77	$	48	$	-	$	-	$	48
U.S. equity securities		-		-		-		-		86		222		-		308
Non-U.S. equity securities		-		-		-		-		79		108		-		187
Global equity securities		118		397		-		515		-		19		-		19
Absolute return		-		-		49		49		-		-		47		47
Real assets		68		-		28		96		31		-		6		37
Fixed-income securities:
U.S. government		148		5		-		153		151		-		-		151
Corporate		9		795		1		805		-		681		1		682
Other		-		38		-		38		1		44		-		45
Total	$	420	$	1,235	$	78	$	1,733	$	396	$	1,074	$	54	$	1,524
Total plan assets at fair value							$	13,767							$	12,529

Schedule Of Level 3 Reconciliation

	Pension Benefits
	Absolute		Corporate		Other
(in millions)	Return		Fixed-Income		Fixed-Income		Real Assets		Total
Balance as of January 1, 2011	$	494	$	549	$	120	$	-	$	1,163
Actual return on plan assets:
Relating to assets still held at the reporting date		5		57		(2)		-		60
Relating to assets sold during the period		2		-		1		-		3
Purchases, issuances, sales, and settlements
Purchases		-		14		2		65		81
Settlements		(14)		(35)		(58)		-		(107)
Transfers out of Level 3		-		-		(63)		-		(63)
Balance as of December 31, 2011	$	487	$	585	$	-	$	65	$	1,137
Actual return on plan  assets:
Relating to assets still held at the reporting date		26		28		-		12		66
Relating to assets sold during the period		-		(1)		-		-		(1)
Purchases, issuances, sales, and settlements
Purchases		-		12		-		208		220
Settlements		-		(13)		-		-		(13)
Balance as of December 31, 2012	$	513	$	611	$	-	$	285	$	1,409

	Other Benefits
	Absolute		Corporate		Other
(in millions)	Return		Fixed-Income		Fixed-Income		Real Assets		Total
Balance as of January 1, 2011	$	47	$	129	$	10		-	$	186
Actual return on plan assets:
Relating to assets still held at the reporting date		1		16		-		-		17
Relating to assets sold during the period		-		(2)		-		-		(2)
Purchases, issuances, sales, and settlements
Purchases		-		34		-		6		40
Settlements		(1)		(30)		(5)		-		(36)
Transfers out of Level 3		-		(146)		(5)		-		(151)
Balance as of December 31, 2011	$	47	$	1	$	-	$	6	$	54
Actual return on plan  assets:
Relating to assets still held at the reporting date		2		-		-		1		3
Relating to assets sold during the period		-		-		-		-		-
Purchases, issuances, sales, and settlements
Purchases		-		1		-		21		22
Settlements		-		(1)		-		-		(1)
Balance as of December 31, 2012	$	49	$	1	$	-	$	28	$	78

Schedule Of Estimated Benefits Expected To Be Paid

(in millions)	Pension		Other		Federal Subsidy
2013	$	581	$	108	$	(6)
2014		618		112		(7)
2015		656		115		(7)
2016		695		119		(8)
2017		732		124		(8)
2018 - 2022		4,172		662		(42)

Schedule Of Employer Contribution Expense

(in millions)
Year ended December 31,
2012	$	67
2011		65
2010		56

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Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Measurements

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 - 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.

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below (assets held in rabbi trusts are held by PG&E Corporation and not the Utility):

	Fair Value Measurements
	At  December 31, 2012
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	209	$	-	$	-	$	-	$	209
Nuclear decommissioning trusts
Money market investments		21		-		-		-		21
U.S. equity securities		940		9		-		-		949
Non-U.S. equity securities		379		-		-		-		379
U.S. government and agency securities		681		139		-		-		820
Municipal securities		-		59		-		-		59
Other fixed-income securities		-		173		-		-		173
Total nuclear decommissioning trusts (2)		2,021		380		-		-		2,401
Price risk management instruments
(Note 10)
Electricity		1		60		80		6		147
Gas		-		5		1		(6)		-
Total price risk management instruments		1		65		81		-		147
Rabbi trusts
Fixed-income securities		-		30		-		-		30
Life insurance contracts		-		72		-		-		72
Total rabbi trusts		-		102		-		-		102
Long-term disability trust
Money market investments		10		-		-		-		10
U.S. equity securities		-		14		-		-		14
Non-U.S. equity securities		-		11		-		-		11
Fixed-income securities		-		136		-		-		136
Total long-term disability trust		10		161		-		-		171
Total assets	$	2,241	$	708	$	81	$	-	$	3,030
Liabilities:
Price risk management instruments
(Note 10)
Electricity	$	155	$	144	$	160	$	(156)	$	303
Gas		8		9		-		(9)		8
Total liabilities	$	163	$	153	$	160	$	(165)	$	311
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Excludes $240 million at December 31, 2012 primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2011
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	206	$	-	$	-	$	-	$	206
Nuclear decommissioning trusts
Money market investments		24		-		-		-		24
U.S. equity securities		841		8		-		-		849
Non-U.S. equity securities		323		-		-		-		323
U.S. government and agency securities		720		156		-		-		876
Municipal securities		-		58		-		-		58
Other fixed-income securities		-		99		-		-		99
Total nuclear decommissioning trusts (2)		1,908		321		-		-		2,229
Price risk management instruments
(Note 10)
Electricity		-		92		69		8		169
Gas		-		6		-		(3)		3
Total price risk management instruments		-		98		69		5		172
Rabbi trusts
Fixed-income securities		-		25		-		-		25
Life insurance contracts		-		67		-		-		67
Total rabbi trusts		-		92		-		-		92
Long-term disability trust
Money market investments		13		-		-		-		13
U.S. equity securities		-		15		-		-		15
Non-U.S. equity securities		-		9		-		-		9
Fixed-income securities		-		145		-		-		145
Total long-term disability trust		13		169		-		-		182
Total assets	$	2,127	$	680	$	69	$	5	$	2,881
Liabilities:
Price risk management instruments
(Note 10)
Electricity	$	411	$	289	$	143	$	(441)	$	402
Gas		31		13		-		(32)		12
Total liabilities	$	442	$	302	$	143	$	(473)	$	414
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Excludes $188 million at December 31, 2011 primarily related to deferred taxes on appreciation of investment value

.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above:

Money Market Investments

PG&E Corporation and the Utility invest 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 U.S. Treasury bills, U.S. agency securities, certificates of deposit, and commercial paper with a maximum weighted average maturity of 60 days or less.  PG&E Corporation's and the Utility's investments in these money market funds are valued using unadjusted prices for identical assets in an active market and are thus classified as Level 1.  Money market funds are recorded as cash and cash equivalents in PG&E Corporation's and the Utility'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 composed primarily of equity securities, debt securities, and life insurance policies.  In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

Equity securities primarily include investments in common stock, which are valued based on unadjusted prices for identical securities in active markets and are classified as Level 1.  Equity securities also include commingled funds composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world, which are classified as Level 2.  Price quotes for the assets held by these funds are readily observable and available.

Debt securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of debt securities classified as Level 2.  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 ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.  (See Note 10 above.)

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model.  Exchange-traded forwards and swaps that are valued using observable market forward prices for the underlying commodity are classified as Level 1.  Over-the-counter forwards and swaps that are identical to exchange-traded forwards and swaps or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2.  Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3.  These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.

Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.  Over-the-counter options are classified as Level 3 and are valued using a standard option pricing model, which includes forward prices for the underlying commodity, time value at a risk-free rate, and volatility.  For periods where market data is not available, the Utility extrapolates observable data using internal models.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  CRRs are valued based on prices observed in the CAISO auction, which are discounted at the risk-free rate.  Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions.  CRRs are classified as Level 3.

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. For the year ended December 31, 2012, there were no significant transfer between levels.

At December 31, 2011, the valuation of price risk management over-the-counter forwards and swaps and exchange-traded options incorporated market observable and market corroborated inputs, where certain previously-considered unobservable inputs became observable.  Therefore, the Utility transferred these instruments out of Level 3 and into Level 2.  There were no significant transfers between Levels 1 and 2 in the year ended December 31, 2011.

Level 3 Measurements and Sensitivity Analysis

The Utility's Market and Credit Risk Management department is responsible for determining the fair value of the Utility's price risk management derivatives.  Market and Credit Risk Management reports to the Chief Risk Officer of the Utility.  Market and Credit Risk Management utilizes models to derive pricing inputs for the valuation of the Utility's Level 3 instruments.  These models use pricing inputs from brokers and historical data.  The Market and Credit Risk Management department and the Controller's organization collaborate to determine the appropriate fair value methodologies and classification for each derivative.  Inputs used and fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.  Valuation models and techniques are reviewed periodically.

CRRs and power purchase agreements are valued using historical prices or significant unobservable inputs derived from internally developed models.  Historical prices include CRR auction prices.  Unobservable inputs include forward electricity prices.  Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively.  All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments.  (See Note 10 above.)

	Fair Value at
(in millions)	December 31, 2012
Fair Value Measurement	Assets		Liabilities		Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights	$	80	$	16	Market approach	CRR auction prices	$	(9.04) - 55.15
Power purchase agreements	$	-	$	145	Discounted cash flow	Forward prices	$	8.59 - 62.90
(1)Represents price per megawatt-hour

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2012 and 2011, respectively:

	Price Risk Management Instruments
(in millions)	2012		2011
Liability balance as of January 1	$	(74)	$	(399)
Realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)		(5)		122
Transfers out of Level 3		-		203
Liability balance as of December 31	$	(79)	$	(74)
(1)Price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and   purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.

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, 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, 2012 and 2011, as they are short-term in nature or have interest rates that reset daily.  

• The fair values of the Utility's fixed-rate senior notes and fixed-rate pollution control bond loan agreements and PG&E Corporation's fixed-rate senior notes were based on quoted market prices at December 31, 2012 and 2011.  The fair value of the ERBs issued by PERF was also based on quoted market prices at December 31, 2011.

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,
	2012				2011
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation	$	349	$	371	$	349	$	380
Utility		11,645		13,946		10,545		12,543
Energy recovery bonds (Note 5)		-		-		423		433

Nuclear Decommissioning Trust Investments

The following table provides a summary of available-for-sale investments held in the Utility's nuclear decommissioning trusts:

				Total		Total
	Amortized			Unrealized		Unrealized		Total Fair
(in millions)	Cost			Gains		Losses		Value (1)
As of December, 2012
Money market investments	$	21	$	-	$	-	$	21
Equity securities
U.S.		331		618		-		949
Non-U.S.		199		181		(1)		379
Debt securities
U.S. government and agency
securities		723		97		-		820
Municipal securities		56		4		(1)		59
Other fixed-income securities		168		5		-		173
Total	$	1,498	$	905	$	(2)	$	2,401
As of December 31, 2011
Money market investments	$	24	$	-	$	-	$	24
Equity securities
U.S.		334		518		(3)		849
Non-U.S.		194		131		(2)		323
Debt securities
U.S. government and agency securities		774		102		-		876
Municipal securities		56		2		-		58
Other fixed-income securities		96		3		-		99
Total	$	1,478	$	756	$	(5)	$	2,229
(1) Excludes $240 million and $188 million at December 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of debt securities by contractual maturity is as follows:

(in millions)	As of December 31, 2012
Less than 1 year	$	5
1-5 years		456
5-10 years		218
More than 10 years		373
Total maturities of debt securities	$	1,052

The following table provides a summary of activity for the debt and equity securities:

	2012		2011		2010
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust
investments	$	1,133	$	1,928	$	1,405
Gross realized gains on sales of securities held as available-for-sale		19		43		42
Gross realized losses on sales of securities held as available-for-sale		(17)		(30)		(11)

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Commitments And Contingencies (Nuclear Insurance) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Long-term Purchase Commitment [Line Items]
Additional annual insurance premium due in conjunction with prolonged outage	$ 44
Full insurance policy limit	3,200
Humboldt Bay Unit 3 liability insurance	53
Coverage for purchased public liability insurance, per incident	375
Diablo Canyon [Member]
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	3,200
Amount of property damage coverage provided by NEIL	2,700
Business interruption	490
Maximum public liability per nuclear incident under Price-Anderson Act	12,600
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act	375
Maximum public liability claims amount per nuclear event	12,600
Maximum total payment incurred per event under the loss sharing program	235
Maximum annual payment incurred per event under the loss sharing program	35
Humboldt Bay Unit [Member]
Long-term Purchase Commitment [Line Items]
Amount of property damage coverage provided by NEIL	131
Amount of indemnification from the NRC for public liability arising from nuclear incidents	500
Amount of liability insurance for Humboldt bay Unit 3	$ 53