10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM10-K

(Mark One)
	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2015
	TRANSITION REPORT PURSUANT TO SECTION 13 OR15(d)OFTHE SECURITIESEXCHANGE 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) 973-1000 (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 Section12(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 Section12(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 ☑ No ☐
Pacific Gas and Electric Company	Yes ☑ 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  ☑
Pacific Gas and Electric Company	Yes ☐ No  ☑

Indicate by check mark whether the registrant (1)has filed all reports required to be filed by Section13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (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 90days.

PG&E Corporation	Yes ☑ No ☐
Pacific Gas and Electric Company	Yes ☑ No ☐

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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 Rule405 of RegulationS-T during the preceding 12months (or for such shorter period that the registrant was required to submit and post such files).

PG&E Corporation	Yes ☑No ☐
Pacific Gas and Electric Company	Yes☑ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of RegulationS-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 PartIII of this Form10-K or any amendment to this Form10-K:

PG&E Corporation	☑
Pacific Gas and Electric Company	☑

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 ☑	Large accelerated filer ☐
Accelerated filer ☐	Accelerated filer ☐
Non-accelerated filer ☐	Non-accelerated filer ☑
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 ☑
Pacific Gas and Electric Company	Yes ☐ No ☑

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June30, 2015, the last business day of the most recently completed second fiscal quarter:

PG&E Corporation common stock	$23,628 million
Pacific Gas and Electric Company common stock	Wholly owned by PG&E Corporation

Common Stock outstanding as of February 12, 2016:

PG&E Corporation:	492,830,471 shares
Pacific Gas and Electric Company:	264,374,809 shares (wholly owned by PG&E Corporation)

DOCUMENTS INCORPORATED BY REFERENCE

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

Designated portions of the Joint Proxy Statement relating to the 2016 Annual Meetings of Shareholders PartIII (Items 10, 11, 12, 13 and 14)

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Contents

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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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GLOSSARY

The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

2015 Form 10-K	PG&E Corporation's and Pacific Gas and Electric Company's combined Annual Report on Form10-K for the year ended December 31, 2015
AB	Assembly Bill
AFUDC	allowance for funds used during construction
ALJ	administrative law judge
ARO	asset retirement obligation
ASU	accounting standard update
CAISO	California Independent System Operator
CARB	California Air Resources Board
CCA	Community Choice Aggregator
Central Coast Board	Central Coast Regional Water Quality Control Board
CEC	California Energy Resources Conservation and Development Commission
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
DOE	Department of Energy
EPA	Environmental Protection Agency
EPS	earnings per common share
EV	electric vehicle
FERC	Federal Energy Regulatory Commission
GAAP	U.S. Generally Accepted Accounting Principles
GHG	greenhouse gas
GRC	general rate case
GT&S	gas transmission and storage
IRS	Internal Revenue Service
LTIP	long term incentive plan
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part II, Item 7, of this Form 10-K
NEIL	Nuclear Electric Insurance Limited
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
ORA	Office of Ratepayer Advocates
PSEP	pipeline safety enhancement plan
QF	Qualifying facility
Regional Board	California Regional Water Quality Control Board, Lahontan Region
REITS	Global real estate investment trust
ROE	return on equity
RPS	renewable portfolio standard
SB	senate bill
SEC	U.S. Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC
TO	transmission owner
TURN	The Utility Reform Network
Utility	Pacific Gasand Electric Company
VIE(s)	variable interest entity(ies)
Water Board	California State Water Resources Control Board

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PART I

ITEM 1. BUSINESS

PG&E Corporation, incorporated in California in 1995, is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, 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 in 1997.  The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.  PG&E Corporation’s and the Utility’s operating revenues, income, and total assets can be found below in Item 6. Selected Financial Data.

The principal executive offices of PG&E Corporation and the Utility are located at 77 Beale Street, P.O.Box 770000, San Francisco, California94177.  PG&E Corporation’s telephone number is (415) 973-1000 and the Utility’s telephone number is (415)973-7000.

At December 31, 2015, PG&E Corporation and the Utility had approximately23,000regular employees,approximately 20 of which were employees of the PG&E Corporation.  Of the Utility’s regular employees, approximately 13,500 are covered by collective bargaining agreements with the local chapters of three labor unions:  the International Brotherhood of Electrical Workers (“IBEW”); the Engineers and Scientists of California (“ESC”); and the Service Employees International Union (“SEIU”).The SEIU collective bargaining agreement will expire on July 31, 2016.The two agreements with IBEW will expire on December31, 2016.The agreement with ESC, originally scheduled to expire on December 31, 2015, automatically renewed for a period of one year pending the negotiation of a new agreement with the union.  In January 2016, the Utility and ESC reached a tentative new agreement, subject to ratification by members of ESC.If ratified, the new agreement with ESC will be retroactive to January 1, 2016 and will expire on December 31, 2019. 

This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility.  PG&E Corporation’s and the Utility’s Annual Reports on Form10-K, Quarterly Reports on Form10-Q, Current Reports on Form8-K, and proxy statements, 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 part of this or any other report that PG&E Corporation and the Utility files with, or furnishes to, the SEC.

In April 2015, the CPUC issued decisions in the three investigations that had been brought against the Utility relating to (1) the Utility’s safety record-keeping 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, record-keeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the pipeline accident that occurred in San Bruno, California on September 9, 2010 (the “San Bruno accident”).  A decision was issued in each investigative proceeding to determine the violations that the Utility committed.  The CPUC also approved a fourth decision (the “Penalty Decision”) to impose penalties on the Utility totaling $1.6 billion.  For more information about the Penalty Decision see Item 1.A. Risk Factors and Note 13 of the Notes to the Consolidated Financial Statementsin Item 8. below.  The Utility also faces criminal charges in the U.S. District Court for the Northern District of California alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act and that the Utility obstructed the NTSB’s investigation into the cause of the San Bruno accident.  The trial currently is scheduled to begin on March 22, 2016.  For more information about the criminal proceeding, see “Enforcement and Litigation Matters” in MD&A,Item 1.A. Risk Factors, and Note 13of the Notes to the Consolidated Financial Statementsin Item 8. below.

This Annual Report on Form 10-K 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 “Item 1A. Risk Factors” and the section entitled “Cautionary Language Regarding Forward-Looking Statements” in MD&A.

Regulatory Environment

The Utility's business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels.  At the state level, the Utility is regulated primarily by the CPUC.  At the federal level, the Utility is subject to the jurisdiction of the FERC and the NRC. The Utility is also subject to the requirements of other federal, state and local regulatory agencies with respect to safety, the environment and health. This section and the “Ratemaking Mechanisms” section below summarize some of the more significant laws, regulations, and regulatory proceedings affecting the Utility.

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PG&E Corporation is a “public utility holding company” as defined under the Public Utility Holding Company Act of 2005 and is subject to regulatory oversight by the FERC.  PG&E Corporation and its subsidiaries are exempt from all requirements of the Public Utility Holding Company Act of 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.

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 transmission 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 enforces state laws and regulations that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas and electric facilities.The CPUC can impose penalties of up to $50,000 per day, per violation, for violations that occurred after January 1, 2012.  (The statutory maximum penalty for violations that occurred before January 1, 2012 is $20,000 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 also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged.

As discussed above, in April 2015, the CPUC concludedits three investigative enforcement actions against the Utility by imposingpenalties totaling $1.6 billion. (For more information about the Penalty Decision, see Item 1.A. Risk Factors and Note 13of the Notes to the Consolidated Financial Statementsin Item 8. below.)The CPUC is also conducting investigative enforcement proceedings relating to the Utility’s natural gas distribution facilities record-keeping practices and the Utility’s potential violations of the CPUC’s ex parte communication rules.  (See “Enforcement and Litigation Matters” in MD&A for more information.)Further, in August 2015, the CPUC began an investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards. (For more information, see “Regulatory Matters” in MD&A.)

The CPUC has adopted separate gas and electric safety enforcement programs that authorize the SED to issue citations and impose fines for violations of certain regulations.Under both the gas and electric programs, the SED is required to impose the maximum statutory penalty of $50,000 for each separate violation and has the discretion to impose daily fines for continuing violations.  During 2016, the CPUC is expected to develop and implement improvements and refinements to the electric and gas safety citation programs, including steps to reconcile the differences between the two programs.

The California State Legislature also directs the CPUC to implement state laws and policies, such as the laws relating to increasing renewable energy resources, the development and widespread deployment of distributed generation and self-generation resources, the reduction of GHG emissions, the development of energy storage technologies and facilities, and the development of a state-wide electric vehicle charging infrastructure.  The CPUC is responsible for approving funding and administration of state-mandated public purpose programs such as energy efficiency and other customer programs.  The CPUC also conducts audits and reviews of the Utility’s accounting, performance and compliance with regulatory guidelines.

The CPUC has imposed various conditions that govern the relationship between the Utility and PG&E Corporation and other affiliates, including financial conditions that require 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. (For more information, see “Liquidity and Financial Resources” in MD&A and Item 1A. Risk Factors.)

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The Federal Energy Regulatory Commission and the California Independent System Operator

The FERC has jurisdiction over the Utility's electricity transmission revenue requirements and rates, the licensing of substantially all of the Utility's hydroelectric generation facilities, and the interstate sale and transportation of natural gas. The FERC regulates the interconnections of the Utility’s transmission systems with other electric systems and generation facilities, the tariffs and conditions of service of regional transmission organizations and the terms and rates of wholesale electricity sales.  The FERC also is charged with adopting and enforcing 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. The FERC has authority to impose fines of up to $1 million per day for violation of certain federal statutes and regulations.

The CAISO is the FERC-approved regional transmission organization for the Utility’s service territory.  The CAISO controls the operation of the electricity transmission system in California and provides open access transmission service on a non-discriminatory basis.  The CAISO also is responsible for planning transmission system additions, ensuring the maintenance of adequate reserves of generation capacity, and ensuring that the reliability of the transmission system is maintained.

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.  (See “Electricity Resources” below.)  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 substantial capital expenditures could be required in the future.  For more information about Diablo Canyon, see “Regulatory Matters – Diablo Canyon” in MD&A and Item 1.A Risk Factors below.)

Other Regulation

The CEC is the state's primary energy policy and planning agency.  The CEC is responsible for licensing all thermal power plants over 50 MW within California.  The CEC also is responsible for forecasts of future energy needs used by the CPUC in determining the adequacy of the utilities' electricity procurement plans.

The 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 implement state law requirements to gradually reduce GHG emissions in California.  (See “Environmental Regulation — Air Quality and Climate Change” below.)

In addition, 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.  The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas that grant the Utility rights to occupy and/or use public property for the operation of the Utility's business and to conduct certain related operations.  The Utility has franchise agreements with approximately 300 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 highways.  In exchange for the right to use public streets and highways, 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.

Ratemaking Mechanisms

The Utility’s rates for electricity and natural gas utility services are set at levels that are intended to allow the Utility to recover its costs of providing service including a return on invested capital (“cost-of-service ratemaking”).  Before setting rates, the CPUC and the FERC conduct proceedings to determine the annual amount that the Utility will be authorized to collect from its customers (“revenue requirements”).  The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administration and general expenses) and capital costs (e.g., depreciation, tax, and financing expenses).  In addition, the CPUC authorizes the Utility to collect revenues to recover costs that it is allowed to “pass-through” to customers (referred to as “Utility Revenues and Costs that did not Impact Earnings” in MD&A), including its costs to procure electricity, natural gas and nuclear fuel, to administer public purpose and customer programs, and to decommission its nuclear facilities.

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The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings.  The authorized rate of return on all other assets is set in the CPUC’s cost of capital proceeding.  Other than its electric transmission and certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume.  Regulatory balancing accounts, or revenue adjustment mechanisms, ensure that the Utility will fully collect its authorized base revenue requirements.  The Utility’s earnings primarily depend on its ability to manage its base operating and capital costs (referred to as “Utility Revenues and Costs that Impacted Earnings” in MD&A) within its authorized base revenue requirements.

Both gas and electric rates vary depending on seasons mostly due to the influence of weather.  Gas service rates generally increase during the winter months (October through March) to account for the gas peak due to heating while electricity rates increase during summer (June – September) because of higher summer costs, driven by air conditioning loads.

During 2015, the CPUC continued to implement state law requirements to reform residential electric rates to more closely reflect the utilities’ actual costs of service, reduce cross-subsidization among customer rate classes, implement new rules and rates for net energy metering (which currently allow certain self-generating customers to receive bill credits for surplus power at the full retail rate), and allow customers to have greater control over their energy use.  (See “Legislative and Regulatory Initiatives” in MD&A for additional information on specific CPUC proceedings.)

From time to time, the CPUC may use incentive ratemaking mechanisms that provide the Utility an opportunity to earn some additional revenues.  For example, the Utility has earned incentives for the successful implementation of energy efficiency programs.  (See “Results of Operations” in MD&A.)These mechanisms can also create financial risk. For a discussion of the re-opened proceeding to review incentive revenues awarded for the 2006-2008 energy efficiency cycle, see “Rehearing of CPUC Decisions Approving Energy Efficiency Incentive Awards” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8. below.

Base Revenues

General Rate Cases

The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s anticipated costs, including return on rate base, related to its electricity distribution, natural gas distribution, and Utility owned electricity generation operations.  The CPUC generally conducts a GRC every three years.  The CPUC approves the annual revenue requirements for the first year (or “test year”) of the GRC period and typically authorizes the Utility to receive annual increases (known as “attrition rate adjustments”) in revenue requirements for the subsequent years of the GRC period.  Attrition rate adjustments are generally provided for cost increases related to increases in invested capital and inflation.  Parties in the Utility's GRC include the ORA and TURN, who generally represent the overall interests of residential customers, as well as a myriad of other intervenors who represent residential and other customer interests.

For more information about the Utility’s current GRC proceeding, see “Regulatory Matters −2017 General Rate Case” in MD&A.

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 the GT&S rate case.  In its 2015 GT&S rate case, the Utility has requested that the CPUC approve a total annual revenue requirement of $1.263 billion for the Utility’s anticipated costs of providing natural gas transmission and storage services for 2015.  The Utility also requested revenue increases of $83 million in 2016 and $142 million in 2017.See “Regulatory Matters – 2015 Gas Transmission and Storage Rate Case” in MD&A for additional information.

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Cost of Capital Proceedings

The CPUC periodically conducts a cost of capital proceeding to authorize the Utility's capital structure and rates of return for its electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base.  The CPUC has authorized the Utility’s capital structure through 2017, consisting of 52% common equity, 47% long-term debt, and 1% preferred stock.  The CPUC also set the authorized ROE at 10.40%.  The CPUC also adopted an adjustment mechanism to allow the Utility’s capital structure and ROE to be adjusted if the utility bond index changes by certain thresholds on an annual basis.  During 2015, the adjustment mechanism was not triggered so the Utility’s authorized ROE will remain at 10.40% for 2016.  On February 12, 2016, a proposed decision was issued, that, if approved by the CPUC, will preclude the Utility from using the mechanism before its next cost of capital application. As a result, if the proposed decision is approved, the Utility’s capital structure and ROE will not be adjusted for 2017. The CPUC will review the Utility’s capital structure and ROE for 2018 in the Utility’s next cost of capital proceeding.  The Utility is required to file its 2018 cost of capital application by April 20, 2017.

Electricity Transmission Owner Rate Cases

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case.  The Utility generally files a TO rate case every year.  The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision.  These FERC-approved rates are included: 1) by the CPUC in the Utility's retail electric rates and are collected from retail electric customers; and 2) by the CAISO in its Transmission Access Charges to wholesale customers.  (See “Regulatory Matters– FERC TORate Cases” in MD&A.)  The Utility also recovers a portion of its revenue requirements for its wholesale electric transmission costs through charges collected under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations.  These wholesale customers are charged individualized rates based on the terms of their contracts.

Revenues to Recover Energy Procurement and Other Pass-Through Costs

Electricity Procurement Costs

California investor-owned electric utilities are responsible for procuring electricity required to meet bundled customer demand, plus applicable reserve margins, that are not satisfied from their own generation facilities and existing electricity contracts.  The utilities are responsible for scheduling and bidding electric generation resources, including electricity procured from third parties or the wholesale market, to meet customer demand according to which resources are the least expensive (i.e., using the principles of “least-cost dispatch”).  In addition, the utilities are required to obtain CPUC approval of their procurement plans based on long-term demand forecasts.  The CPUC has approved the Utility’s procurement plancovering 2012 through 2024.

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 by the CPUC.  The CPUC may disallow costs associated with electricity purchasesif the costs were not incurred in compliance with the CPUC-approved plan or if the CPUC determines that the utility failed to follow the principles of least-cost dispatch. 

The Utility recovers its electricity procurement costs annually primarily through the energy resource recovery account.  (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.) Each year, the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements, derivative instruments, GHG emissions costs, and generation fuel expense, and approves a forecasted revenue requirement.  The CPUC may adjust the Utility’s retail electricity rates more frequently if the forecasted aggregate over-collections or under-collections in the energy resource recovery account exceed 5% of its prior year electricity procurement and utility-owned generation revenues.  The CPUC performs an annual compliance review of the transactions recorded in the energy resource recovery account.

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, to meet mandatory renewable energy targets, and to comply with resource adequacy requirements.  For additional information, see “Electric Utility Operations – Electricity Resources” below as well as Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

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Natural Gas Procurement and Transportation Costs

The Utility sets the natural gas procurement rate for small commercial and residential customers (referred to as “core” customers) monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs.  The Utility recovers the cost of gas purchased on behalf of core customers as well as the cost of derivative instruments through its retail gas rates that are subject to limits as set forth in its core procurement incentive mechanism, described below.  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 rate changes.  The Utility recovers the cost of gas used in generation facilities as a cost of electricity that is recovered annually through retail electricity rates.

The core procurement incentive mechanism protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs.  Under the core procurement incentive mechanism, 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 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.

The Utility incurs transportation costs under various agreements with interstate and Canadian third-party transportation service providers.  These providers 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 agreements are governed by FERC-approved 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.  The FERC approves the United States tariffs that shippers, including the Utility, pay for pipeline service, 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 a cost of electricity.

Costs Associated with Public Purpose and Customer Programs

The CPUC authorizes the Utility to recover the costs of various public purpose and other customer programs through the collection of rates from most Utility customers. These programs relate to energy efficiency, demand response, distributed generation, energy research and development, and other matters. Additionally, the CPUC has authorized the Utility to provide a discount rate for low-income customers, known as California Alternate Rates for Energy (“CARE”), which is subsidized by the Utility’s other customers.

Nuclear Decommissioning Costs

The Utility's nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  Nuclear decommissioning costs are collected in advance through rates and are held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit.  The Utility files an application with the CPUC every three years requesting approval of the Utility’s updated estimated decommissioning costs and any rate change necessary to fully fund the nuclear decommissioning trusts to the levels needed to decommission the Utility’s nuclear plants.

Electric Utility Operations

The Utility generates electricity and provides electricity transmission and distribution services throughout its service territory in northern and central California to residential, commercial, industrial, and agricultural customers.  The Utility provides “bundled” services (i.e., electricity, transmission and distribution services) to most customers in its service territory.  Customers also can obtain electricity from alternative providers such as municipalities or CCAs, as well as from self-generation resources, such as rooftop solar installations.

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As required by California law, on July 1, 2015, the Utility filed its proposed electric distribution resources plan for approval by the CPUC. The Utility’s plan identifies optimal locations on its electric distribution system for deployment of distributed energy resources.  The Utility’s proposal is designed to allow energy technologies to be interconnected with each other and integrated into the larger grid while continuing to provide customers with safe, reliable and affordable electric service.  The Utility envisions a future electric grid, titled the Grid of Things™, that would allow customers to choose new advanced energy supply technologies and services to meet their needs consistent with safe, reliable and affordable electric service.  The CPUC also is considering the Utility’s request for approval of the phased deployment of an electric vehicle charging infrastructure in response to the CPUC’s December 2014 decision adopting a policy to expand the California utilities’ role in developing an EV charging infrastructure to support California’s climate goals.  (For more information, see “Legislative and Regulatory Initiatives” in MD&A.)

Electricity Resources

The Utility is required to maintain generating capacity adequate to meet its customers’ demand for electricity (“load”), including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service.  The Utility is required to dispatch, or schedule all of the electricity resources within its portfolio in the most cost-effective way.

The following table shows the percentage of the Utility’s total deliveries of electricity to customers in 2015 represented by each major electricity resource, and further discussed below.

Total 2015 Actual Electricity Generated and Procured –72,113GWh (1):

		Percent of Bundled Retail Sales
Owned Generation Facilities
	Nuclear		22.6	%
	Small Hydroelectric		0.7	%
	Large Hydroelectric		4.6	%
	Fossil fuel-fired		8.9	%
	Solar		0.4	%
	Total				37.2	%
Qualifying Facilities
	Renewable		3.0	%
	Non-Renewable		6.5	%
	Total				9.5	%
Irrigation Districts and Water Agencies
	Small Hydroelectric		0.1	%
	Large Hydroelectric		0.6	%
	Total				0.7	%
Other Third-Party Purchase Agreements
	Renewable		25.3	%
	Large Hydroelectric		0.7	%
	Non-Renewable		9.4	%
	Total				35.4	%
Others, Net(2)					17.2	%
Total (3)					100	%

(1) This amount excludes electricity provided to direct access customers and CCAs who procure their own supplies of electricity.

(2) Mainly comprised of netCAISO open market purchases.

(3) Non-renewable sources, including nuclear, large hydroelectric, and fossil fuel-fired are offset by transmission and distribution related system losses.

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Renewable Energy Resources.  California law established a “renewable portfolio standard” (referred to as “RPS”) thatrequires load-serving entities, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers.  In October 2015, the California Governor signed SB 350, the Clean Energy and Pollution Reduction Act of 2015 which, effective January 1, 2016, increases the amount of renewable energy that must be delivered by most load-serving entities, including the Utility, to their customers from 33% of their total annual retail sales by the end of the 2017-2020 compliance period to 50% of their total annual retail sales by the end of the 2028- 2030 compliance period and in each compliance period thereafter.  SB 350 establishes increasing interim renewable energy targets for the periods between 2020 and 2030 but also provides compliance flexibility and waiver mechanisms, including increased flexibility to apply excess renewable energy procurement in one compliance period to future compliance periods.  The Utility will incur additional costs to procure renewable energy to meet the new renewable energy targets which the Utility expects will continue to be recoverable from customers as “pass-through” costs. The Utility also may be subject to penalties for failure to meet the higher targets.  The CPUC has stated its intent to propose a decision in late 2016 implementing SB 350’s provisions requiring higher RPS targets and other changes made by the statute to the RPS rules.

Renewable generation resources, for purposes of the RPS requirements, include bioenergy such as biogas and biomass, certain hydroelectric facilities (30 MW or less), wind, solar, and geothermal energy.  During 2015, 29.5%of the Utility’s energy deliveries were from renewable energy sources, exceeding the annual RPS target of 23.3%.  Approximately 25% of the renewable energy delivered to the Utility’s customers was purchased from non-QF third parties.Additional renewable resources were provided by QFs (3.0%), the Utility’s small hydroelectric facilities (0.7%), and the Utility’s solar facilities (0.4%).

The total 2015 renewable deliveries shown above were comprised of the following:

Type	GWh	Percent of Bundled Retail Sales
Biopower	3,141	4.4%
Geothermal	3,664	5.0%
Wind	5,451	7.6%
Solar	8,157	11.3%
RPS-Eligible Hydroelectric	878	1.2%
Total	21,291	29.5%

Energy Storage.  As required by California law, the CPUC has established initial energy storage procurement targets to be achieved by each load-serving entity, such as the Utility.  The Utility must hold Requests for Offers (RFOs) to meet biennial targets and procure 580 MW of energy storage which must be operational by the end of 2024.  The Utility’s 2014-2015 energy storage procurement target was 80.5 MW.  The Utility initiated its RFO on December 1, 2014 to obtain at least 74 MW of transmission and distribution connected energy storage, signed contracts for 75 MW, and submitted those contracts for CPUC approval on the CPUC’s December 1, 2015 deadline.  The Utility met its remaining 6.5 MW customer-connected target by funding energy storage under the CPUC-mandated Self Generation Incentive Program. On January 1, 2016, the Utility reported its compliance with its 2014-2015 obligations to the CPUC.  The Utility must file its 2016-2017 plan for procuring 120 MW of energy storage, consisting of 105 MW of transmission and distribution energy storage and 15 MW of customer-connected storage, by March 1, 2016.  A CPUC decision on the Utility’s plan is expected before the December 1, 2016 deadline for the Utility to issue its second energy storage RFO.  The Utility continues to participate in the CPUC proceeding to refine California’s energy storage program, which is considering potentially higher targets and expanded energy storage use cases.

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Owned Generation Facilities.  At December 31, 2015, 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 (1):
Diablo Canyon	San Luis Obispo	2	2,240
Hydroelectric (2):
Conventional	16 counties in northern and central California	104	2,684
Helms pumped storage	Fresno	3	1,212
Fossil fuel-fired:
Colusa Generating Station	Colusa	1	657
Gateway Generating Station	Contra Costa	1	580
Humboldt Bay Generating Station	Humboldt	10	163
Fuel Cell:
CSU East Bay Fuel Cell	Alameda	1	1
SF State Fuel Cell	San Francisco	2	2
Photovoltaic (3):	Various	13	152
Total		137	7,691

(1)The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2.  The NRC operating licenses expire in 2024 and 2025, respectively.  (See “Diablo Canyon Nuclear Power Plant” in. MD&A and Item 1A. Risk Factors.)

(2) The Utility’s hydroelectric system consists of 107 generating units at 67 powerhouses. All of the Utility’s powerhouses are licensed by the FERC (except for two small powerhouses not subject to FERC licensing requirements), with license terms between 30 and 50 years.

(3) The Utility’s larger operational photovoltaic 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), the Giffen solar station (10 MW), the Gates solar station (20 MW), the West Gates solar station (10 MW) and the Guernsey solar station (20 MW). All of these facilities are located in Fresno County, except for the Guernsey solar station, which is located in Kings County.

Generation Resources from Third Parties.  The Utility has entered into various agreements to purchase power and electric capacity, including agreements for renewable energy resources, in accordance with its CPUC-approved procurement plan.  (See “Ratemaking Mechanisms” above.)  For more information regarding the Utility’s power purchase agreements, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

Electricity Transmission

At December31, 2015, the Utility owned approximately 18,400 circuit miles of interconnected transmission lines operating at voltages ranging from 60 kV to 500 kV.  The Utility also operated 91 electric transmission substations with a capacity of approximately 63,400 MVA.  The Utility’s electric transmission system is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes many western states, Alberta and British Columbia, and parts of Mexico.

In 2013, the Utility, MidAmerican Transmission, LLC, and Citizens Energy Corporation were selected by the CAISO to jointly develop a new 230-kV transmission line to address the growing power demand in Fresno, Madera and Kings counties area.  The 70-mile line will connect the Utility-owned and -operated Gates and Gregg substations.  The new line will help reduce the number and duration of power outages, improve voltage in the area, support economic development, and bolster efforts to integrate clean, renewable energy onto the grid.  The transmission line is expected to commence operations by 2022, and could come online earlier.

Throughout 2015, the Utility upgraded several critical substations and re-conductored a number of transmission lines to improve maintenance and system flexibility, reliability and safety.  The Utility expects to undertake various additional transmission projects over the next several years to upgrade and expand the capacity of its transmission system to accommodate system load growth, secure access to renewable generation resources, replace aging or obsolete equipment and improve system reliability.  The Utility also has taken steps to improve the physical security of its transmission substations and equipment.

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Electricity Distribution

The Utility's electricity distribution network consists of approximately 142,000 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead), 58 transmission switching substations, and 603 distribution substations, with a capacity of approximately 31,400 MVA.  The Utility’s distribution network interconnects with its transmission system, primarily at switching and distribution substations, where equipment reduces the high-voltage transmission voltages to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’s customers.

These distribution substations serve as the central hubs for the Utility’s electric distribution network.  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 facilities to entities, such as municipal and other utilities, that resell the electricity.  In 2015 the Utility commenced operations in a new electric distribution control center facility in Rocklin, California, and expects to complete an additional facility in Concord, California, in 2016.  These control centers form a key part of the Utility’s efforts to create a smarter, more resilient grid.

In 2015, the Utility continued to deploy its Fault Location, Isolation, and Service Restoration circuit technology which involves the rapid operation of smart switches to reduce the duration of customer outages. Another 83 circuits were outfitted with this equipment, bringing the total deployment to 700 of the Utility’s 3200 distribution circuits. The Utility also installed or replaced 20 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 2016.

Electricity Operating Statistics

The following table shows certain of the Utility’s operating statistics from 2013 to 2015 for electricity sold or delivered, including the classification of revenues by type of service.No single customer of the Utility accounted for 10% or more of consolidated revenues for electricity sold in 2015, 2014 and 2013.

		2015		2014		2013
Customers (average for the year)		5,311,178		5,276,025		5,243,216
Deliveries (in GWh) (1)		85,860		86,303		86,513
Revenues (in millions):
Residential	$	5,032	$	4,784	$	5,091
Commercial		5,278		5,141		4,905
Industrial		1,555		1,543		1,388
Agricultural		1,233		1,172		1,021
Public street and highway lighting		83		79		75
Other (2)		(84)		(172)		(128)
Subtotal		13,097		12,547		12,352
Regulatory balancing accounts (3)		560		1,109		137
Total operating revenues	$	13,657	$	13,656	$	12,489
Selected Statistics:
Average annual residential usage (kWh)		6,294		6,458		6,752
Average billed revenues per kWh:
Residential	$	0.1719	$	0.1603	$	0.1643
Commercial		0.1640		0.1585		0.1499
Industrial		0.0973		0.0998		0.0928
Agricultural		0.1610		0.1516		0.1454
Net plant investment per customer	$	6,660	$	6,339	$	6,002

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

(2) This activity is primarily related to a remittance of revenue to the Department of Water Resources (“DWR”) (the Utility acts as a billing and collection agent on behalf of the DWR), partially offset by other miscellaneous revenue items.

(3)These amounts represent revenues authorized to be billed. 

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Natural Gas Utility Operations

The Utility provides natural gas transportation services to “core” customers (i.e., small commercial and residential customers) and to “non-core” customers (i.e., industrial, large commercial, and natural gas-fired electric generation facilities) that are connected to the Utility’s gas system in its service territory. Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or non-utility third-party gas procurement service providers (referred to as core transport agents). When core customers purchase gas supply from a core transport agent, the Utility continues to provide gas delivery, metering and billing services to customers.When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service. Currently, more than 91% of core customers, representing nearly 80% of the annual core market demand, receive bundled natural gas service from the Utility.

The Utility does not provide procurement service to non-core customers, who must purchase their gas supplies from third-party suppliers.  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 also delivers gas to off-system customers (i.e., outside of the Utility’s service territory) and to third-party natural gas storage customers.

Natural Gas Supplies

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 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 2015, the Utility purchased approximately 307,100 MMcf of natural gas (net of the sale of excess supply of gas).  Substantially all this natural gas was purchased under contracts with a term of one year or less.  The Utility’s largest individual supplier represented approximately 17% of the total natural gas volume the Utility purchased during 2015.

Natural Gas System Assets

The Utility owns and operates an integrated natural gas transmission, storage, and distribution system that includes most of northern and central California.  At December 31, 2015, the Utility’s natural gas system consisted of approximately 42,800 miles of distribution pipelines, over 6,700 miles of backbone and local transmission pipelines, and various storage facilities.  The Utility owns and operates eight natural gas compressor stations on its backbone transmission system and one small station on its local transmission system that are used to move gas through the Utility’s pipelines.  The Utility’s backbone transmission system, composed primarily of Lines 300, 400, and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution systems.

The Utility 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 LinesLtd., B.C. System.  These companies’ pipeline systems connect at the border to the pipeline system owned by Gas Transmission Northwest, LLC, 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 also 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 the U.S. Southwest to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona.  The Utility also has a transportation agreement with Kern River Gas Transmission Company to transport gas from the U.S. Rocky Mountains to the interconnection point with the Utility’s natural gas system in the area of Daggett, California.  For more information regarding the Utility’s natural gas transportation agreements, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility owns and operates three underground natural gas storage fields and has a 25% interest in a fourth storage field, all of which are connected to the Utility’s transmission system. The Utility owns and operates compressors and other facilities at these storage fields that are used to inject gas into the fields for storage and later withdrawal. In addition, four independent storage operators are interconnected to the Utility's northern California transmission system.

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During 2015, the Utility conducted an annual system-wide review of its transmission pipeline class location designations.  The Utility also continued work to install 217 automatic and remote control shut-off valves on its gas transmission system, as specified in the eleventh of twelve safety recommendations made by the NTSB following its investigation of the San Bruno accident.  As of December 31, 2015, the Utility had installed 235 automatic and remote control shut-off valves, and the NTSB closed that recommendation.  The final safety recommendation, considered open and acceptable by the NTSB, involves hydrostatic testing nearly 1,000 miles of the Utility’s gas transmission system. The Utility has completed the majority of this task and currently plans to complete the task for the remaining approximately 100 of pipelines (involving primarily short pipeline segments that include tie-in pieces, fittings or smaller diameter off-takes from the larger transmission pipelines) during 2018. Also, as part of the Utility’s distribution integrity management program, the Utility completed approximately 23,500 sewer inspections during 2015 to identify and correct conflicts between gas and waste water facilities.

Natural Gas Operating Statistics

The following table shows the Utility's operating statistics from 2013 through 2015 (excluding subsidiaries) for natural gas, including the classification of revenues by type of service.No single customer of the Utility accounted for 10% or more of consolidated revenues for bundled gas sales in 2015, 2014 and 2013.

		2015		2014		2013
Customers (average for the year)		4,415,332		4,394,283		4,378,797
Gas purchased (MMcf)		209,194		202,215		240,414
Average price of natural gas purchased	$	2.11	$	4.09	$	3.29
Bundled gas sales (MMcf):
Residential		144,885		143,514		181,775
Commercial		43,888		42,080		46,668
Total Bundled Gas Sales		188,773		185,594		228,443
Revenues (in millions):
Bundled gas sales:
Residential	$	1,816	$	1,683	$	1,870
Commercial		403		419		395
Other		125		51		44
Bundled gas revenues		2,344		2,153		2,309
Transportation service only revenue		649		662		555
Subtotal		2,993		2,815		2,864
Regulatory balancing accounts		183		617		240
Total operating revenues	$	3,176	$	3,432	$	3,104
Selected Statistics:
Average annual residential usage (Mcf)		35		34		44
Average billed bundled gas sales revenues per Mcf:
Residential	$	12.53	$	11.72	$	10.29
Commercial		9.18		9.96		8.47
Net plant investment per customer	$	2,573	$	2,468	$	2,234

Competition

Competition in the Electricity Industry

California law allows qualifying non-residential electric customers of investor-owned electric utilities to purchase electricity from energy service providers rather than from the utilities up to certain annual and overall GWh limits that have been specified for each utility.  This arrangement is known as “direct access.”In addition, California law permits cities, counties, and certain other public agencies that have qualified to become a “community choice aggregator” (or “CCA”) to generate and/or purchase electricity for their local residents and businesses. By law, a CCA can procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from a utility.

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The Utility continues to provide transmission, distribution, metering, and billing services to direct access customers, although these customers can choose to obtain metering and billing services from their energy service provider.  The CCA customers continue to obtain transmission, distribution, metering, and billing services from the Utility.  In addition to collecting charges for transmission, distribution, metering, and billing services that it provides, the Utility is able to collect charges to recover the generation-related costs that the Utility incurred on behalf of direct access and CCA customers while they were the Utility’s customers. The Utility remains the electricity provider of last resort for these customers.

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, may seek to acquire the Utility’s distribution facilities, either under a consensual transaction or via eminent domain.

The Utility is also impacted by the increasing viability of distributed generation and energy storage.  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.

The Utility also competes for the opportunity to develop and construct certain types of electric transmission facilities within, or interconnected to, its service territory through a competitive bidding process managed by the CAISO.

Competition in the Natural Gas Industry

The Utility primarily 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 Utility also competes for storage services with other third-party storage providers, primarily in northern California.

Environmental Regulation

The Utility’s operations are subject to extensive 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 remediation of hazardous and radioactive substances; the discharge of pollutants into the air, water, and soil; the reporting and reduction of carbon dioxide (CO­2)and other GHG emissions; the transportation, handling, storage and disposal of spent nuclear fuel; 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.  (See Item 1A. Risk Factors.)  Generally, the Utility recovers most of 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 in Note 13: Contingencies—Environmental Remediation Contingencies, of the Notes to the Consolidated Financial Statements in Item 8.

Hazardous Waste Compliance and Remediation

The Utility's facilities are subject to the requirements of the federal Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980 as amended.  The Utility is also subject to the regulations adopted by the EPA, the federal agency responsible for implementing the federal environmental laws.  The Utility also must comply with environmental laws and regulations adopted by the State of California and various state and local agencies.  These federal and state laws impose strict liability for the release of a hazardous substance on the (1) owner or operator of the site where the release occurred, (2) on companies that disposed of, or arranged for the disposal of, the hazardous substances, and (3) in some cases, their corporate successors.  Under the Comprehensive Environmental Response, Compensation and Liability Act, these persons (known as “potentially responsible parties”) may be jointly and severally liable for the costs of cleaning up the hazardous substances, paying for the harm caused to natural resources, and paying for the costs of required health studies.

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The Utility has a comprehensive program in place to comply with these federal, state, and local laws and regulations.  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.  The Utility’s remediation activities are overseen by the California Department of Toxic Substances Control, several California regional water quality control boards, and various other federal, state, and local agencies.  The Utility has incurred significant environmental remediation liabilities associated with 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.  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.

For more information about environmental remediation liabilities, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

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, CO2, sulfur dioxide (SO2), mono-nitrogen oxide (NOx), particulate matter, and other GHG emissions.

In December 2009, the EPA concluded that GHG emissions contribute to climate change and issued a finding that GHG emissions cause or contribute to air pollution that endangers public health and welfare. In May 2014, the U.S. Global Change Research Program (a confederation of the research arms of thirteen federal departments and agencies) released its third National Climate Assessment, which stated that the global climate is changing and that impacts related to climate change are already evident in many sectors and are expected to become increasingly disruptive across the nation throughout this century and beyond.

Federal Regulation.  At the federal level, the 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.

In August 2015, the EPA published final regulations under section 111(b) of the Clean Air Act to control CO2emissions from new fossil fuel-fired power plants.  While these regulations do not affect the Utility’s existing power plants, the regulations impose emission limitations on fossil fuel-fired power plants constructed after January 8, 2014 and will affect the design, construction, operation and cost of such power plants. 

In August 2015, the EPA also published final regulations under section 111(d) of the Clean Air Act to controlCO2 emissions from existing fossil fuel-fired power plants.  These regulations are designed to reduce power plant CO2 emissions on a national basis by as much as 32% by 2030, compared with 2005 levels.  States must submit final plans to comply with these regulations by September 2016, but may request an extension to file such plans until September 2018. It is uncertain whether and how these federal regulations will ultimately impact California, since existing state regulation currently requires, among other things, the gradual reduction of state-wide GHG emissions to 1990 levels by 2020.Following publication of the EPA’s regulations, in October 2015 West Virginia and several other states and parties challenged the EPA’s section 111(d) regulations in the United States Court of Appeals for the District of Columbia Circuit and petitioned the Court to stay the regulations pending review of the appeal on the merits.  The D.C. Circuit denied the request for stay but in February 2016, the United States Supreme Court granted a stay of the section 111(d) regulations pending review of the appeal by the D.C. Circuit.  The Supreme Court’s decision may affect the nature, extent and timing of implementation of these regulations.  As described below, the Utility expects all costs and revenues associated with the state-wide, comprehensive cap-and-trade program to be passed through to customers.

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State Regulation.  California’s AB 32, the Global Warming Solutions Act of 2006, provides for the gradual reduction of state-wide GHG emissions to 1990 levels by 2020.  The CARB has approved various regulations to achieve the 2020 target, including GHG emissions reporting and 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 major GHG emission sources within different sectors of the economy.  The cap-and-trade program’s first compliance period, which began on January 1, 2013, applied to the electricity generation and large industrial sectors.  The next compliance period, which began on January 1, 2015, expanded to include the natural gas and transportation sectors, effectively covering all the economy’s major sectors until 2020.  The Utility’s compliance obligation as a natural gas supplier applies to the GHG emissions attributable to the combustion of natural gas delivered to the Utility’s customers other than natural gas delivery customers that are separately regulated as covered entities and have their own compliance obligation.  During each year of the program, the CARB issues emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year.  Emitterscan obtain allowances from the CARB at quarterly auctions or from third parties or exchanges.  Emitters may also satisfy a portion of their compliance obligation through the purchase of offset credits; e.g., credits for GHG reductions achieved by third parties (such as landowners, livestock owners, and farmers) that occur outside of the emitters’ facilities through CARB-qualified offset projects such as reforestation or biomass projects.  During 2016, CARB and the California Legislature are likely to consider proposals to achieve additional GHG reductions beyond the 2020 target established in AB 32.  The Utility expects all costs and revenues associated with the GHG cap-and-trade program to be passed through to customers.  The California RPS program that requires the utilities to gradually increase the amount of renewable energy delivered to their customers is also expected to help reduce GHG emissions in California.

Climate Change Mitigation and Adaptation Strategies. During 2015, 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 plan for the actions that it will need to take to adapt to the likely impacts of climate change on the Utility’s future operations.  The Utility regularly reviews the most relevant scientific literature on climate change such as sea level rise, temperature changes, rainfall and runoff patterns, and wildfire risk, to help the Utility identify and evaluate climate change-related risks and develop the necessary adaptation strategies.  The Utility maintains emergency response plans and procedures to address a range of near-term risks, including extreme storms, heat waves and wildfires and uses its risk-assessment process to prioritize infrastructure investments for longer-term risks associated with climate change. The Utility also engages with leaders from business, government, academia, and non-profit organizations to share information and plan for the future.

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, persistent, and frequent hot weather.  The Utility believes its strategies to reduce GHG emissions through energy efficiency and demand response programs, infrastructure improvements, and the use of renewable energy and energy storage are effective strategies for adapting to the expected increase in demand for electricity.  The Utility is making substantial investments to build a more modern and resilient system that can better withstand extreme weather and related emergencies.The Utility’s vegetation management activities also reduce the risk of wildfire impacts on electric and gas facilities.  Over the long-term, the Utility also faces the risk of higher flooding and inundation potential at coastal and low elevation facilities due to sea level risecombined with high tides, storm runoff and storm surges.

Climate scientists also predict that climate change will result in significant reductions in snowpack in parts of the Sierra Nevada Mountains.  This could, in turn, affect the Utility’s hydroelectric generation.  To plan for this potential change, the Utility is engaging with state and local stakeholders and is also adopting strategies such as maintaining higher winter carryover reservoir storage levels, reducing discretionary reservoir water releases, and collaborating on research and new modeling tools.

With respect to natural gas operations, both safety-related pipeline strength testing and normal pipeline maintenance and operations release the GHG methane into the atmosphere.  The Utility has taken steps to reduce the release of methane by implementing techniques including drafting and cross-compression, which reduce the pressure and volume of natural gas within pipelines prior to venting. In addition, the Utility continues to achieve reductions in methane emissions by implementing improvements in leak detection and repair, upgrades at metering and regulating stations, and maintenance and replacement of other pipeline materials.

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Emissions Data

PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas.  The Utility reports its GHG emissions to the CARB and the EPA on a mandatory basis. On a voluntary basis, the Utility reports a more comprehensive emissions inventory to The Climate Registry, a non-profit organization.  The Utility’s third-party verified voluntary GHG inventory reported to The Climate Registry for 2014 totaled more than 58 million metric tonnes of CO­2 equivalent, nearly two-thirds of which came from customer natural gas use.  The following table shows the 2014 GHG emissions data the Utility reported to the CARB under AB 32. PG&E Corporation and the Utility publish additional GHG emissions data in their annual Corporate Responsibility and Sustainability Report.

Source	Amount (metric tonnes CO2 equivalent)
Fossil Fuel-Fired Plants (1)	2,407,734
Natural Gas Compressor Stations and Storage Facilities (2)	348,155
Distribution Fugitive Natural Gas Emissions	750,223
Customer Natural Gas Use (3)	41,616,935

(1) Includes nitrous oxide and methane emissions from the Utility’s generating stations.

(2) Includes compressor stations and storage facilities emitting more than 25,000 metric tonnes of CO2 equivalent annually.

(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.

The following table shows the Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2014 as compared to the national average for electric utilities:

	Amount (pounds of CO2 per MWh)
U.S. Average (1)	1,137
Pacific Gas and Electric Company (2)	435

(1) Source: EPA eGRID.

(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 emissions rate.

Air Emissions Data for Utility-Owned Generation

In addition to GHG emissions data provided above, the table below sets forth information about the air emissions from the Utility’s owned generation facilities.  The Utility’s owned generation (primarily nuclear and hydroelectric facilities) comprised approximately 36% of the Utility’s delivered electricity in 2014.  PG&E Corporation and the Utility also publish air emissions data in their annual Corporate Responsibility and Sustainability Report.

	2014	2013
Total NOx Emissions (tons)	141	153
NOx Emissions Rate (pounds/MWh)	0.01	0.01
Total SO2 Emissions (tons)	14	17
SO2 Emissions Rate (pounds/MWh)	0.0010	0.0011

Water Quality

On May 19, 2014, the EPA issued final regulations to implement the requirements of the federal Clean Water Act that require cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, to reflect the best technology available to minimize adverse environmental impacts. Various industry and environmental groups have challenged the federal regulations in proceedings pending in the U.S. Court of Appeals for the Fourth Circuit.  California’s once-through cooling policy discussed below is considered to be at least as stringent as the new federal regulations.  Therefore, California’s implementation process for the state policy will likely continue without any significant change.

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At the state level,in 2010 the California Water Board adopted a policy on once-through cooling that generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities in California by at least 85%.As required by the policy the California Water Board appointed a committee to evaluate the feasibility and cost of using alternative technologies to achieve compliance at Diablo Canyon. The committee’s consultant submitted its final report to the California Water Board in September 2014 and the board is not expected to issue a final decision regarding Diablo Canyon’s compliance with the state policy beforeJanuary 2017.  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. Even if the Utility is not required to install cooling towers, it could incur significant costs to comply with alternative compliances measures or to make payments to support various environmental mitigation projects. The Utility would seek to recover such costs in rates.  The Utility’s Diablo Canyon operations must be in compliance with the California Water Board’s policy by December 31, 2024.

The final requirements of the federal and state cooling water policies could affect future negotiations between the Central Coast Board and the Utility regarding the status of the 2003 settlement agreement.  (See “Diablo Canyon Power Plant” in Item 3. Legal Proceedings below.)

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’ customers.  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.  As a result, the Utility constructed interim dry cask storage facilities to store its spent fuel onsite at Diablo Canyon and at Humboldt Bay until the DOE fulfills its contractual obligation to take possession of the spent fuel.  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.

In September 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.  The settlement agreement also provided a claims process by which the Utility submits annual requests for reimbursement of its ongoing spent fuel storage costs.  In 2015, the Utility was awarded an additional $21 million for costs incurred between June 1, 2013 and May 31, 2014.  The claim for the period June 1, 2014 through May 31, 2015 is under review by the DOE.  These proceeds are being refunded to customers through rates.  The settlement agreement, as amended, does not address costs incurred for spent fuel storage beyond 2016 and such costs could be subject to 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 fuel.

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ITEM 1A. RISK FACTORS

PG&E Corporation’s and the Utility’s financial results can be affected by many factors, including estimates and assumptions used in the critical accounting policies described in MD&A, that can cause their actual financial results to differ materially from historical results or from anticipated future financial results.The following discussion of key risk factors should be considered in evaluating an investment in PG&E Corporation and the Utility and should be read in conjunction with MD&A and the consolidated financial statements and related notes in Part II, Item 8, “Financial Statements and Supplementary Data” of this Form 10-K.  Any of these factors, in whole or in part, could materially affect PG&E Corporation’s and the Utility’s business, results of operations, financial condition, and stock price.

Risks Relatedto the Outcome of Enforcement Matters, Investigations, and Regulatory Proceedings

PG&E Corporation’s and the Utility’s future financial results may be materially affected by the outcome of the federal criminal prosecution of the Utility. 

As discussed in MD&A, theUtility is facing federal criminal charges alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act and alleging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident that occurred on September 9, 2010.  The maximum statutory fine for each felony count is $500,000, for potential total fines of $6.5 million.  The federal prosecutor also seeks to impose an alternative fine whichcould total approximately $562 million, based on allegations that the Utility derived gross gains of approximately $281 million.  The trial currently is scheduled to begin on March 22, 2016.

PG&E Corporation and the Utility have not recorded any charges for potential criminal fines in their consolidated financial statements at December 31, 2015.  If the Utility is convicted and a fine is imposed, PG&E Corporation and the Utility will record charges when required in accordance with GAAP.  The Utility also could incur material costs, not recoverable through rates, to implement remedial measures that may be imposed by the court,such as a requirement that theUtility’s natural gas operations be supervised by a third-party monitor. The Utility could also be suspended or debarred from entering into federal procurement and non-procurement contracts and programs.

If the Utility incurred material fines or costs following a conviction, PG&E Corporation may need to issue common stock to raise funds to contribute to the Utility to maintain the required equity component of the Utility’s authorized capital structure as the Utility incur charges and costs.  These issuances would be incremental to PG&E Corporation’s current forecast of common stock issuances and could materially dilute PG&E Corporation’s EPS.  The trial and any negative publicity associated with it, as well as the Utility’s conviction and the imposition of a material fine, if incurred, also could affect the Utility’s and PG&E Corporation’s credit ratings or outlooks and make it more difficult for PG&E Corporation and the Utility to access the capital markets.

The trial and the Utility’s conviction could harm the Utility’s relationships with regulators, legislators, communities, business partners, or other constituencies and make it more difficult to recruit qualified personnel and senior management.  Further, they could negatively affect the outcome of future ratemaking and regulatory proceedings;for example, by enabling parties to challenge the Utility’s request to recover costs that the parties allege are somehow related to the criminal charges.

In addition, the Utility’s conviction could result in increased regulatory or legislative pressure to require the separation of the Utility’s electric and natural gas businesses, restructure the corporate relationship between PG&E Corporation and the Utility, or undergo some other fundamental corporate restructuring.  As discussed under the heading “Regulatory Matters”in MD&A, the SED will evaluate PG&E Corporation’s andthe Utility’s organizational structure in the CPUC’s pending investigation to examine the Utility’s safety culture.

PG&E Corporation’s and the Utility’s future financial results may be materially affected by the outcomes of the CPUC’s investigative enforcement proceedings against the Utility, other known enforcement matters, and other ongoing state and federal investigations.  The Utility also could incur material costs and fines in connection with future investigations, citations, audits, or enforcement actions.

The Utility could incur material charges, including fines and other penalties, in connection with the CPUC’s investigations of the Utility’s compliance with natural gas distribution record-keeping practices and the Utility’s compliance with the CPUC’s rules regarding ex parte communications.  In addition, there are several other investigations by federal and state law enforcement authorities.  The Utility was informed that the U.S. Attorney’s Office was investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014.  The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case discussed above.  Federal and state law enforcement authorities also have been investigating matters related to allegedly improper communication between the Utility and CPUC personnel.  If these investigations result in enforcement action against the Utility, the Utility could incur additional fines or penalties or suffer negative consequences described above in the immediately preceding risk factor.In addition, anegative outcome in any of these investigations or future enforcement actions may negatively affect the outcome of future ratemaking and regulatory proceedings; for example, by enabling parties to challenge the Utility’s request to recover costs that the parties allege are somehow related to the Utility’s violations.

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The SED also could impose material fines on the Utility based on the Utility’s self-reports submitted in accordance with the SED’s safety citation program and the Utility’s efforts to identify and remove encroachments from transmission pipeline rights of way.  The Penalty Decision requires the SED to review the Utility’s gas transmission operations (including the Utility’s compliance with the remedies ordered by the Penalty Decision) and to perform annual audits of the Utility’s record-keeping practicesfor a minimum of ten years. The SED could impose fines on the Utility or require the Utility to incur unrecoverable costs, or both, based on the outcome of these future audits. In addition, although PG&E Corporation and the Utility do not currently face the possibility of fines or penalties in the first phase of the CPUC’s pending investigation into the Utility’s safety culture since it has been categorized as rate setting, it is uncertain how the next phase will be categorized.  (See the discussion under the heading “Regulatory Matters” in MD&A.)

The Utility could be subject to additional regulatory or governmental enforcement action in the future with respect to compliance with federal, state or local laws, regulations or orders that could result in additional fines, penalties or customer refunds, including those regarding renewable energy and resource adequacy requirements; customer billing; customer service; affiliate transactions; vegetation management; design, construction, operating and maintenance practices; safety and inspection practices; and federal electric reliability standards.  The SED could impose fines on the Utility in the future in accordance with its authority under the gas and electric safety citation programs.  The amount of such fines, penalties, or customer refunds could have a material effect on PG&E Corporation’s and the Utility’s financial results.

PG&E Corporation’s and the Utility’s future financial results could be materially affected by the extent to which its natural gas transmission costs exceed authorized revenues as the Utility complies with the Penalty Decision and incurs other natural gas transmission costs that are unrecoverable or that the Utility has not sought to recover. 

The Utility’s ability to recover its natural gas transmission and storage costs and earn its authorized ROE could be materially affected by the amount of revenues the CPUC ultimately authorizes the Utility to collect in the 2015 GT&S rate case proceeding and future GT&S rate cases.  (See “RegulatoryMatters” in Item 7. MD&A.)  The Utility continues to incur material unrecoverable costs to meet the Penalty Decision’s requirement to fund safety-related projects and programs to be identified by the CPUC in the 2015 GT&S rate case.  Depending on how the CPUC designates pipeline safety-related projects and programs the Utility is required to fund, and how the Utility’s associated costs are counted toward meeting the $850 million maximum disallowance imposed by the Penalty Decision, the ultimate amount of unrecoverable pipeline-related costs the Utility incurs may be higher than current forecasts.  In addition, the Penalty Decision requires the Utility to implement various remedial measures which the CPUC estimated would cost $50 million.  Actual costs to implement the remedies could be higher.

In addition, the Utility plans to incur unrecoverable costs to continue performing certain work to complete projects under the PSEP and to identify and remove encroachments from gas transmission pipeline rights-of-way.  Actual costs to perform this work could exceed forecasts.

PG&E Corporation’s and the Utility’s financial results primarily depend on the outcomes of  regulatory and ratemaking proceedings and the Utility’s ability to manage its operating expenses and capital expenditures so that it is able to earn its authorized rate of return in a timely manner.

As a regulated entity, the Utility’s rates are set by the CPUC or the FERC on a prospective basis and are generally designed to allow the Utility to collect sufficient revenues to recover the costs of providing service, including a return on its capital investments.  PG&E Corporation’s and the Utility’s financial results could be materially affected if the CPUC or the FERC does not authorize sufficient revenues for the Utility to safely and reliably serve its customers and earn its authorized ROE.The outcome of the Utility’s ratemaking proceedings can be affected by many factors, including the Utility’s reputation (especially if the Utility is convicted of the federal criminal charges discussed above), the level of opposition by intervening parties; potential rate impacts; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of the Utility’s regulators, consumer and other stakeholder organizations, and customers, about the Utility’s ability to provide safe, reliable, and affordable electric and gas services.

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The Utility also is required to incur costs to comply with legislative and regulatory requirements and initiatives, such as those relating to the development of a state-wide electric vehicle charging infrastructure, the deployment of distributed energy resources, implementation of demand response and customer energy efficiency programs, energy storage and renewable energy targets, and the construction of the California high-speed rail project.  The Utility’s ability to recover costs, including its investments, associated with these and other legislative and regulatory initiativeswill, in large part, depend on the final form of legislative or regulatory requirements, and whether the associated ratemaking mechanisms can be timely adjusted to reflect changes in customer demand for the Utility’s electricity and natural gas services.

In addition to the amount of authorized revenues, PG&E Corporation’s and the Utility’s financial results could be materially affected if the Utility’s actual costs to safely and reliably serve its customers differ from authorized or forecast costs.  The Utility may incur additional costs for many reasons including changing market circumstances, unanticipated events (such as storms, accidents, catastrophic or other events affecting the Utility’s operations), or compliance with new state laws or policies.  Although the Utility may be allowed to recover some or all of the additional costs, there may be a substantial time lag between when the Utility incurs the costs and when the Utility is authorized to collect revenues to recover such costs.  Alternatively, the CPUC or the FERC may disallow costs that they determine were not reasonably or prudently incurred by the Utility.

The Utility’s ability to recover its costs also may be affected by the economy and its 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 or the level of uncollectible bills could increase.  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. 

Changes in commodity prices also may have an adverse effect on the Utility’s ability to timely recover its operating costs and earn its authorized ROE. Although the Utility generally recovers its electricity and natural gas procurement costs from customers as “pass-through” costs, a significant and sustained rise in commodity prices could create overall rate pressures that make it more difficult for the Utility to recover its costs that are not categorized as “pass-through” costs.To relieve some of this upward rate pressure, the CPUC could authorize lower revenues than the Utility requested or disallow full cost recovery. 

PG&E Corporation’s and the Utility’s financial results depend upon the Utility’s continuing ability to recover “pass-through” costs, including electricity and natural gas procurement costs, from customers  in a timely manner.  The CPUC may disallow procurement costs for a variety of reasons. In addition, the Utility’s ability to recover these costs could be affected by the loss of Utility customers and decreased new customer growth, if the CPUC fails to adjust the Utility’s rates to reflect such events.

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 commercial and CPUC regulatory principles of “least cost dispatch” and prudent administration of power purchase agreements in compliance with its CPUC-approved long-term procurement plan.  The CPUC could disallow procurement costs incurred by the Utility if the CPUC determines that the Utility did not comply with these principles or if the Utility did not comply with its procurement plan. 

Further, the contractual prices for electricity under the Utility’s current or future power purchase agreements could 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 adverse economic conditions or the loss of the Utility’s customers to other retail providers.In particular, the Utility will incur additional costs to procure renewable energy to meet the higher targets established by California SB 350 that became effective on January 1, 2016.  Despite the CPUC’s current approval of the contracts, the CPUC could disallow contract costs in the future if it determines that the costs are unreasonably above market. 

The Utility’s ability to recover the costs it incurs in the wholesale electricity market may be affected by the whether the CAISO wholesale electricity market continues to function effectively.  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. The CPUC could prohibit the Utility from passing through the higher costs of electricity to customers.  For example, during the 2000 and 2001 energy crisis, the market mechanism flaws in California’s then-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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Further, PG&E Corporation’s and the Utility’s financial results could be affected by the loss of Utility customers and decreased new customer growth that occurs through municipalization of the Utility’s facilities, an increase in the number of CCAs who provide electricity to their residents, and an increase in the number of consumers who become direct access customers of alternative generation providers.  (See “Competition in the Electricity Industry” in Item 1.)  As the number of bundled customers (i.e., those primarily residential customers who receive electricity and distribution service from the Utility) declines, the rates for remaining customers could increase as the Utility would have a smaller customer base from which to recover certain procurement costs.  Although the Utility is permitted to collect non-bypassable charges for generation-related costs incurred on behalf of former customers, the charges may not be sufficient for the Utility to fully recover these costs.  In addition, the Utility’s ability to collect non-bypassable charges has been, and may continue to be, challenged by certain customer groups.  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 (“NEM”), which allows self-generating customers to receive bill credits for surplus power at the full retail rate, puts upward rate pressure on remaining customers. In January 2016, the CPUC adopted new NEM rules and rates. The new rules and rates are expected to become effective for new NEM customers of the Utility later in 2016. New NEM customers will be required to pay an interconnection fee, will go on time of use rates, and will be required to pay some non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay. However, the resulting rules will still put upward rate pressure on remaining customers, and remove the cap on the number of NEM customers. Significantly higher rates for remaining customers may result in a decline of the number of such customers as they may seek alternative energy providers. The CPUC states that it intends to revisit these rules in 2019.

A confluence of technology-related cost declines and sustained federal or state subsidies could make a combination of distributed generation and energy 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.  If the number of the Utility’s customers decreases or grows at a slower rate than anticipated, the Utility’s level of capital investment would likely decline as well, in turn leading to a slower growth in rate base and earnings.  Reduced energy demand or significantly slowed growth in demand due to customer migration to other energy providers, adoption of energy efficient technology, conservation, increasing levels of distributed generation and self-generation, unless substantially offset through regulatory cost allocations, could adversely impact PG&E Corporation’s and the Utility’s financial results.

The CPUC has begun to implement rate reform to allow residential electric rates to more closely reflect the utilities’ actual costs of providing service and decrease cost-subsidization among customer classes.  Many aspects of rate reform are not yet finalized, including time-of-use rates and whether the utilities can impose a fixed charge on certain customers.  If the Utility is unable to recover a material portion of its procurement costs and/or if the CPUC fails to adjust the Utility’s rates to reflect the impact of changing loads, the wide deployment of distributed generation, and the development of new electricity generation and energy storage technologies, PG&E Corporation’s and the Utility’s financial results could be materially affected. 

Risks Related to Liquidity and Capital Requirements

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

PG&E Corporation and the Utility will continue to seek funds in the capital and credit markets to enable the Utility to make capital investments, pay fines that may be imposed in the future, and incur costs to meet the Penalty Decision’s requirement to incur costs of up to $850 million for safety-related projects and programs to be identified by the CPUC in the 2015 GT&S rate case.  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 primarily on PG&E Corporation’s and the Utility’s credit ratings and outlook.  Their credit ratings and outlook can be affected by many factors, including the outcomes of the on-going criminal prosecution, the pending CPUC investigations, and ratemaking proceedings.  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 would be negatively affected and could result in higher borrowing costs, fewer financing options, including reduced, or lack of, access to the commercial paper market, additional collateral posting requirements, which in turn could affect liquidity and lead to an increased financing need.  Other factors can affect the availability and terms of debt and equity financing, including 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, an increase in interest rates by the Federal Reserve Bank, and general economic and financial market conditions.

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The reputations of PG&E Corporation and the Utility continue to suffer from the negative publicity about matters discussed under “Enforcement and Litigation Matters” in Item 7. MD&A.  The negative publicity and the uncertainty about the outcomes of these matters may undermine investors’ confidence in management’s ability to execute its business strategy and restore a constructive regulatory environment.  As a result, investors may be less willing to buy shares of PG&E Corporation common stock resulting in a lower stock price.  Further, the market price of PG&E Corporation common stock could decline materially after the outcomes are determined.  The amount and timing of future share issuances also could affect the stock price. 

If the Utility were unable to access the capital markets, it could be required to decrease or suspend dividends to PG&E Corporation and PG&E Corporation could be required to contribute capital to the Utility to enable the Utility to fulfill its obligation to serve.  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.  

PG&E Corporation’s ability to meet its debt service and other financial obligations and to pay dividends on its common stock depends on the Utility’s earnings and cash flows.

PG&E Corporation is a holding company with no revenue generating operations of its own. 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, before it can distribute cash to PG&E Corporation.  Under the CPUC’s rules applicable to utility holding companies, the Utility’s dividend policy must be established by the Utility's Board of Directors as though the Utility were a stand-alone utility company and PG&E Corporation’s 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 CPUC has interpreted this “first priority” obligation to include the requirement that PG&E Corporation “infuse the Utility with all types of capital necessary for the Utility to fulfill its obligation to serve.”  In addition, before the Utility can pay common stock dividends to PG&E Corporation, the Utility must maintain its authorized capital structure with an average 52% equity component. 

If the Utility were required to pay a material amount of fines or incur material unrecoverable costs due to a conviction in the on-going criminal prosecution, the pending CPUC investigations, or other enforcement matters, it would require equity contributions from PG&E Corporation to restore its capital structure.  PG&E Corporation common stock issuances used to fund such equity contributions could materially dilute EPS. (See “Liquidity and Financial Resources” in Item 7. MD&A.)  Further, if PG&E Corporation were required to infuse the Utility with significant capital or if the Utility was unable to distribute cash to PG&E Corporation, or both, PG&E Corporation may be unable to pay principal and interest on its outstanding debt, pay its common stock dividend, or meet other obligations.

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%.

Risks Related to Operations and Information Technology

The Utility’s electricity and natural gas operations are inherently hazardous and involve significant risks which, if they materialize, can adversely affect PG&E Corporation’s and the Utility’s financial results.  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.  (See “Electric Utility Operations” and “Natural Gas Utility Operations” in Item 1. Business.)  The Utility’s ability to earn its authorized ROE depends on its ability to efficiently maintain, operate, and protect its facilities, and provide electricity and natural gas services safely and reliably.  The Utility undertakes substantial capital investment projects to construct, replace, and improve its electricity and natural gas facilities.  In addition, the Utility is obligated to decommission its electricity generation facilities at the end of their useful operating lives.  The Utility’s ability to safely and reliably operate, maintain, construct and decommission its facilities is subject to numerous risks, many of which are beyond the Utility’s control, including 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;  

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·   an overpressure event occurring on natural gas facilities due to equipment failure, incorrect operating procedures or failure to follow correct operating procedures, or welding or fabrication-related defects, that results in the failure of downstream transmission pipelines or distribution assets and uncontained natural gas flow;  

· failure to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled/uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life;  

· aprolonged statewide electrical black-out that results  in damage to the Utility’s equipment or damage to property owned by customers or other third parties;  

· the failure to fully identify, evaluate, and control workplace hazards that result in serious injury or loss of life for employees or the public, environmental damage, or reputational damage;  

· the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act;  

· the failure of a large dam or other major hydroelectric facility, or the failure of one or more levees that protect land on which the Utility’s assets are built;  

· 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 (such as a wild land fire or natural gas explosion), and the failure to respond effectively to a catastrophic event;

· inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that can lead to public or employee harm or extended outages;  

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

· operator or other human error;  

· an ineffective records management program that results in the failure to construct, operate and maintain a utility system safely and prudently;  

· construction performed by third parties that damage the Utility’s underground or overhead facilities, including, for example, ground excavations or “dig-ins” that damage the Utility’s underground pipelines;  

· the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; flaking lead paint from the Utility's facilities, and leaking or spilled insulating fluid from electrical equipment; and

· attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war.

The occurrence of any of these events could interrupt fuel supplies; affect demand for electricity or natural gas; cause unplanned outages or reduce generating output; damage the Utility’s assets or operations; damage the assets or operations of third parties on which the Utility relies; damage property owned by customers or others; and cause personal injury or death.  As a result, the Utility could incur costs to purchase replacement power, to repair assets and restore service, and to compensate third parties.  In particular, the Utility may incur material liability in connection with a wildfire (known as the “Butte fire”) that ignitedand spread in Amador and Calaveras counties in Northern California in September 2015 depending on the outcome of the investigations into the cause of the fire. If insurance recoveries are unavailable or insufficient to cover such costs, PG&E Corporation’s and the Utility’s financial condition or results of operations could be materially affected.  The Utility also could incur material fines, penaltiesor disallowances, as a result of enforcement actions taken by the CPUC or other law enforcement agencies.

Further, although the Utility often enters into agreements for third-party contractors to perform work, such as patrolling and inspection of facilities or the construction or demolition or facilities, the Utility may retain liability for the quality and completion of the contractor’s work and can be subject to penalties or other enforcement action if the contractor violates applicable laws, rules, regulations, or orders.  The Utility may also be subject to liability, penalties or other enforcement action as a result of personal injury or death caused by third-party contractor actions.  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 results.  Future insurance coverage may not be available at rates and on terms as favorable as the Utility’s current insurance coverage or may not be available at all.

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The Utility’s operational and information technology systems could fail to function properly or be damaged by third parties (including cyber-attacks and acts of terrorism), severe weather, natural disasters, or other events. Any of these events could disrupt the Utility’s operations and cause the Utility to incur unanticipated losses and expense or liability to third parties.

The operation of the Utility’s extensive electricity and natural gas systems relies on evolving and increasingly complex operational and information technology systems and network infrastructures that are interconnected with the systems and network infrastructure owned by third parties.  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. Despite implementation of security measures, all of the Utility’s technology systems are vulnerable to disability or failures due to hacking, viruses, acts of war or terrorism and other causes.  The failure of the Utility’s operational and information technology systems and networks could significantly disrupt operations; cause harm to the public or employees; result in outages or reduced generating output; damage 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 results.

The Utility’s systems, including its financial information, operational systems, advanced metering, and billing systems, require ongoing maintenance, modification, and updating, which can be costly and increase the risk of errors and malfunction. The Utility often relies on third-party vendors to maintain, modify, and update its systems and these third-party vendors could cease to exist.  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 Utility’s ability to maintain effective financial controls, and/or the Utility’s ability to timely file required regulatory reports.The Utility also could be subject to patent infringement claims arising from the use of third-party technology by the Utility or by a third-party vendor.

In addition, the Utility’s information systems contain confidential information, including information about customers and employees.  The theft, damage, or improper disclosure of confidential information can subject the Utility to penalties for violation of applicable privacy laws, subject the Utility to claims from third parties, reduce the value of proprietary information, and harm the Utility’s reputation.

The operation and decommissioning of the Utility’s nuclear power plants expose it to potentially significant liabilities and the Utility may not be able to fully recover its costs if regulatory requirements change or the plant ceases operations before the licenses expire.

The operation of the Utility’s nuclear generation facilities exposes 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, and the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act. 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 results. In addition, the Utility may be required under federal law to pay up to $255 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 13 of the Notes to the Consolidated Financial Statements in Item 8.)

In addition, the Utility continues to face public concern about the safety of nuclear generation and nuclear fuel. Some of these nuclear opposition groups regularly file petitions at the NRC and in other forums challenging the actions of the NRC and urging governmental entities to adopt laws or policies in opposition to nuclear power. Although an action in opposition may ultimately fail, regulatory proceedings may take longer to conclude and be more costly to complete. It is also possible that public pressure could grow leading to adverse changes in legislation, regulations, orders, or their interpretation.  As a result, operations at the Utility’s two nuclear generation units at Diablo Canyon could cease before the licenses expire in 2024 and 2025. In such an instance, the Utility could be required to record a charge for the remaining amount of its unrecovered investment and such charge could have a material effect on PG&E Corporation and the Utility’s financial results.

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The Utility has incurred, and may continue to incur, substantial costs to comply with NRC regulations and orders. (See “Regulatory Environment” in Item 1. Business.) If the Utility were unable to recover these costs, PG&E Corporation’s and the Utility’s financial results 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; alternatively, the NRC may order the Utility to cease operations until the Utility can comply with new regulations, orders, or decisions.The Utility may incur a material charge if it ceases operations at Diablo Canyon before the licenses expire in 2024 and 2025.  At December 31, 2015, the Utility’s unrecovered investment in Diablo Canyon was $2.3 billion.

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%. 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. Even if the Utility is not required to install cooling towers, it could incur significant costs to comply with alternative compliances measures or to make payments to support various environmental mitigation projects.

Further, the Utility’s leases of coastal land occupied by the water intake and discharge structures for the nuclear generation units at Diablo Canyon expire in 2018 and 2019.  The Utility has requested that the California State Lands Commission renew the leases until 2024 and 2025 when the NRC licenses expire.  The California State Lands Commission has deferred acting on the application until later in 2016.  It is uncertain what level of environmental review, if any, will be required before the leases can be extended.  If the leases are not extended or if the Utility determines that it cannot comply with any new environmental conditions in a feasible and economic manner, then operations at Diablo Canyon would cease and the Utility could incur a material charge for the remaining amount of its unrecovered investment.

The Utility also has an obligation to decommission its electricity generation facilities, including its nuclear facilities, as well as gas transmission system assets, at the end of their useful lives. (See Note 2: Summary of Significant Accounting Policies – Asset Retirement Obligations of the Notes to the Consolidated Financial Statement in Item 8.) The CPUC authorizes the Utility to recover its estimated costs to decommission its nuclear facilities through nuclear decommissioning charges that are collected from customers and held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit. If the Utility’s actual decommissioning costs, including the amounts held in the nuclear decommissioning trusts, exceed estimated costs, PG&E Corporation’s and the Utility’s financial results could be materially affected.

Risks Related to Environmental Factors

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 results.

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 incurs significant capital, operating, and other costs associated with compliance with these environmental statutes, rules, and regulations.  The Utility has been in the past, and may be in the future, required to pay for environmental remediation costs at sites where it is identified as a potentially responsible party under federal and state environmental laws.  Although the Utility has recorded liabilities for known environmental obligations, these costs can be difficult to estimate due to uncertainties about the extent of contamination, remediation alternatives, the applicable remediation levels, and the financial ability of other potentially responsible parties.  (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8 for more information.)  

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 fines or other sanctions. 

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.

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Some of the Utility’s environmental costs, such as the remediation costs associated with the Hinkley natural gas compressor site, are not recoverable through rates or insurance.  (See “Environmental Regulation” in Item 1.) 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 results.  Their financial results also can be materially affected by changes in estimated costs and by the extent to which actual remediation costs differ from recorded liabilities.

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. 

The Utility has been studying the potential effects of climate change (increased temperatures, changing precipitation patterns, rising sea levels) on the Utility’s operations and is developing contingency plans to adapt to those events and conditions that the Utility believes are most significant.  Scientists project that climate change will increase electricity demand due to more extreme, persistent and hot weather.  Increasing temperatures and changing levels of precipitation in the Utility’s service territory would reduce snowpack in the Sierra Mountains.  If the levels of snowpack were reduced, the Utility’s hydroelectric generation would decrease and the Utility would need to acquire additional generation from other sources at a greater cost.If the Utility increasesits reliance on conventional generation resources to replace hydroelectric generation and to meet increased customer demand, it may become more costly for the Utility to comply with GHG emissions limits.  In addition, increasing temperatures and lower levels of precipitation could increase the occurrence of wildfires in the Utility’s service territory causing damage to the Utility’s facilities or the facilities of third parties on which the Utility relies to provide service, damage to third parties for loss of property, personal injury, or loss of life.In addition, flooding caused by rising sea levels could damage the Utility’s facilities, including hydroelectric assets such as dams and canals, and the electric transmission and distribution assets.  The Utility could incur substantial costs to repair or replace facilities, restore service, compensate customers and other third parties for damages or injuries. The Utility anticipates that the increased costs would be recovered through rates, but as rate pressures increase, the likelihood of disallowance or non-recovery may increase. 

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.

Other Risk Factors

The Utility may be required to incur substantial costs in order to obtain or renew licenses and permits needed to operate the Utility’s business and the Utility may be subject to fines and penalties for failure to comply or obtain license renewal.

The Utility must comply with the terms of various governmental permits, authorizations, and licenses, including those issued by the FERC for the continued operation of the Utility’s hydroelectric generation facilities, and those issued by environmental and other federal, state and local governmental agencies. Many of the Utility’s capital investment projects, and some maintenance activities, often require the Utility to obtain land use, construction, environmental, or other governmental permits.  These permits, authorizations, and licenses may be difficult to obtain on a timely basis, causing work delays.  Further, existing permits and licenses could 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, the Utility often seeks periodic renewal of a license or permit, such as a waste discharge permit or a FERC operating license for a hydroelectric generation facility.  If a license or permit is not renewed for a particular facility and the Utility is required to cease operations at that facility, the Utility could incur an impairment charge or other costs.  Before renewing a permit or license, the issuing agency may impose additional requirements that may increase the Utility’s compliance costs.  In particular, 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.  In addition, local governments may attempt to assert jurisdiction over various utility operations by requiring permits or other approvals that the Utility has not been previously required to obtain.

The Utility may incur penalties and sanctions for failure to comply with the terms and conditions of licenses and permits which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.  If the Utility cannot obtain, renew, or comply with necessary governmental permits, authorizations, licenses, ordinances, or other requirements, or if the Utility cannot recover the increase in associated compliance and other costs in a timely manner, PG&E Corporation’s and the Utility’s financial results could be materially affected. 

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Poor investment performance or other factors 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.  The performance of the debt and equity markets affects the value of plan assets and trust assets.  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 interest rates used to measure the required minimum funding levels, the rate of return on plan assets, employee demographics, discount rates used in determining future benefit obligations, rates of increase in health care costs, future government regulation, and prior contributions to the plans.  Similarly, funding requirements for the nuclear decommissioning trusts are affected by the rates of return on trust assets, changes in the laws or regulations regarding nuclear decommissioning or decommissioning funding requirements as well as changes in assumptions or forecasts related to decommissioning dates, technology and the cost of labor, materials and equipment.  (See Note 2: Summary of Significant Accounting Policies of the Notes to the Consolidated Financial Statements in Item 8.) If the Utility is required to make significant unplanned contributions to fund the pension and postretirement plans or if actual nuclear decommissioning costs exceed the amount of nuclear decommissioning trust funds and the Utility is unable to recover the contributions or additional costs in rates, PG&E Corporation’s and the Utility’s financial results could be materially affected.

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 are or 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 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.  Labor disruptions could occur depending on the outcome of negotiations to renew the terms of these agreements with the unions or if tentative new agreements are not ratified by their members.  In addition, some of the remaining non-represented Utility employees could join one of these unions in the future. 

PG&E Corporation and the Utility also 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 ongoing enforcement proceedings.  Any such occurrences could negatively impact PG&E Corporation’s and the Utility’s financial condition and results of operations.

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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 in Item 1. Business, under “Electric Utility Operations” and “Natural Gas Utility Operations.”  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 total, the Utility occupies 11.1 million square feet of real property, including 8.9 million square feet owned by the Utility.  The Utility's corporate headquarters comprises approximately 1.7 million square feet located in several Utility-owned buildings in San Francisco, California.

PG&E Corporation also leases approximately 42,000 square feet of office space from a third party in San Francisco, California.  This lease will expire in 2022.

The Utility currently owns approximately 168,000 acres of land, including approximately 140,000 acres of watershed lands.  In 2002 the Utility agreed to implement its “Land Conservation Commitment” (“LCC”) to permanently preserve the six “beneficial public values” on all the watershed lands through conservation easements or equivalent protections, as well as to make approximately 70,000 acres of the watershed lands available for donation to qualified organizations.  The six “beneficial public values” being preserved by the LCC include: natural habitat of fish, wildlife, and plants; open space; outdoor recreation by the general public; sustainable forestry; agricultural uses; and historic values.  The Utility’s goal is to implement all the transactions needed to implement the LCC by the end of 2018, subject to securing all required regulatory approvals.

ITEM 3. LEGAL PROCEEDINGS

In addition to the following proceedings, PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business.For more information regarding material lawsuits and proceedings, see “Enforcement and Litigation Matters” in Note13 of the Notes to the Consolidated Financial Statements in Item 8 and in Item 7. MD&A.

Penalty Decision Related to the CPUC’s Investigative Enforcement Proceedings Related to Natural Gas Transmission

On April 9, 2015, the CPUC approved final decisions in the three investigations that had been brought against the Utility relating to (1) the Utility’s safety record-keeping 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, record-keeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010.  A decision was issued in each investigative proceeding to determine the violations that the Utility committed.  The CPUC also approved a fourth decision (the “Penalty Decision”) which imposes penalties on the Utility totaling $1.6 billion comprised of: (1) a $300 million fine to be paid to the State General Fund, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million.  In August 2015, the Utility paid the $300 million fine.At December 31, 2015, the Consolidated Balance Sheets include $400 million in current liabilities – other for the one-time bill credit that will be provided to the Utility’s natural gas customers in 2016.  On January 14, 2016, the CPUC issued final decisions to close these investigative proceedings.

The Penalty Decision requires that at least $689 million of the $850 million disallowance be allocated to capital expenditures, and that the Utility be precluded from including these capital costs in rate base.  The CPUC will determine which safety projects and programs will be funded by shareholders in the Utility’s pending 2015 GT&S rate case.  If the $850 million is not exhausted by designated safety-related projects and programs in the 2015 GT&S proceeding, the CPUC will identify additional projects in future proceedings to ensure that the full $850 million is spent. The CPUC is expected to issue a final decision in the Utility’s 2015 GT&S rate case in 2016 to identify safety-related projects and programs that will be subject to the disallowance. It is uncertain how much of the Utility’s costs to perform the safety-related projects and programs the CPUC will identify as counting toward the $850 million shareholder-funded obligation. If the Utility’s actual costs exceed costs that the CPUC counts towards the $850 million maximum, the Utility would record additional charges if such costs are not otherwise authorized by the CPUC.  As a result, the total shareholder-funded obligation could exceed $850 million.  For more information, see “Enforcement and Litigation Matters” in Note 13: Contingencies and Commitments of the Notes to the Consolidated Financial Statements in Item 8.

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Federal Criminal Indictment

On July 29, 2014, a federal grand jury for the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court that superseded the original indictment that was returned on April 1, 2014.  The superseding indictment charges 27 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats.  The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident.  On December 23, 2015, the court presiding over the federal criminal proceeding dismissed 15 of the Pipeline Safety Act counts, leaving 13remaining counts.  The maximum statutory fine for each felony count is $500,000 for total potential fines of $6.5 million.  On December 8, 2015, the court also issued an order granting, in part, the Utility’s request to dismiss the government’s allegations seeking an alternative fine under the Alternative Fines Act.  (The Alternative Fines Act states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.”)  The court dismissed the government’s allegations regarding the amount of losses, but concluded that it required additional information about how the government would prove its allegations about the amount of the gross gain prior to deciding whether to dismiss those allegations. (Based on the superseding indictment’s allegation that the Utility derived gross gains of approximately $281 million, the potential maximum alternative fine would be approximately $562 million.) After considering the additional information submitted by the government, on February 2, 2016, the court issued an orderholding that if the government’s allegations about the Utility’s gross gains are considered, they would be considered in a second trial phase that would take place after the trial on the criminal charges. The trial on the criminal charges currently is scheduled to begin March 22, 2016.

The Utility entered a plea of not guilty.The Utility believes that criminal charges and the alternative fine allegations are not merited and that it did not knowingly and willfully violate minimum safety standards under the Natural Gas Pipeline Safety Act or obstruct the NTSB’s investigation, as alleged in the superseding indictment.  PG&E Corporation and the Utility have not accrued any charges for criminal fines in their Consolidated Financial Statements as such amounts are not considered to be probable.

Litigation Related to the San Bruno Accident and Natural Gas Spending

As of December 31, 2015, there were six purported derivative lawsuits seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims.

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Four of the complaints were consolidated as the San Bruno Fire Derivative Cases and are pending in the Superior Court of California, County of San Mateo.  On August 28, 2015, the Superior Court overruled the demurrers filed by PG&E Corporation, the Utility and the individual director and officer defendants seeking to dismiss the San Bruno Fire Derivative Cases, based upon the plaintiffs’ failure to demand action by the Boards of PG&E Corporation and the Utility prior to filing the complaint.  After the ruling, and pursuant to co-petitions for writ of mandate previously filed by PG&E Corporation, the Utility, and the individual defendants, on September 3, 2015, the California Court of Appeal issued an order staying the San Bruno Fire Derivative Cases pending the court’s final determination whether to stay the matter altogether until the resolution of federal criminal proceedings against the Utility.  On September 30, 2015, PG&E Corporation, the Utility, and the individual defendants filed an additional petition for writ of mandate asking the Court of Appeal to review the lower court’s August 28 decision overruling their demurrers.  On October 22, 2015, the Court of Appeal issued a ruling declining to review the August 28 decision.  On December 8, 2015, the Court of Appeal issued a writ of mandate to the Superior Court, ordering the Superior Court to stay all proceedings in the San Bruno Fire Derivative Cases “pending conclusion of the federal criminal proceedings” against the Utility.  The other two derivative actions are entitled Tellardin v. PG&E Corp. et. al., pending in the Superior Court of California, San Mateo County, and Iron Workers Mid-South Pension Fund v. Johns, et. al., pending in the United States District Court for the Northern District of California.  PG&E Corporation, and the other defendants have not answered or otherwise responded to the complaints in these actions.  In the Tellardin action, the defendants must answer or respond to the complaint 30 days after the stay in the San Bruno Fire Derivative Cases is lifted.  In the Iron Workers action, the court has not established a deadline by which the defendants must answer or respond.  Case management conferences have been scheduled in both actions (March 21, 2016 in the Tellardin action and June 3, 2016 in the Iron Workers action), after which PG&E Corporation will have more information about any further proceedings in these actions. 

Investigation of the Butte Fire

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California.  The California Department of Forestry and Fire Protection (“Cal Fire”) is investigating the source of the Butte Fire to determine whether a tree contacted a power line operated by the Utility and was the cause of the fire.  Cal Fire has reported that as a result of the fire there were two deaths and 965 structures, including 571 houses, were damaged or destroyed. Cal Fire’s investigation is expected to conclude in 2016.

Approximately 27 complaints have been filed against the Utility and its vegetation management contractors in the Superior Court of California in both the County of Calaveras and the County of San Francisco, involving more than 600 individual plaintiffs and their insurance companies. Plaintiffs and the Utility filed petitions with the California Judicial Council to coordinate these cases.  The petitions were assigned to the Calaveras Superior Court for a recommendation to the Judicial Council.  On January 21, 2016, the Calaveras Superior Court issued an order recommending to the Judicial Council that the cases be coordinated in the Superior Court of California, Sacramento County, for all purposes including trial.  Among other factors, the Court found that coordination requires a court with a significant number of judges and complex litigation support personnel, neither of which are present in Calaveras County.  For additional information, see “Enforcement and Litigation Matters” in Note 13: Contingencies and Commitments of the Notes to the Consolidated Financial Statements in Item 8.

Other Enforcement Matters

The Utility also could be required to pay fines, or incur other unrecoverable costs, associated with the CPUC’s pending investigations of the Utility’s natural gas distribution facilities record-keeping practices and the Utility’s potential violations of the CPUC’s ex parte communication rules.  In addition, fines may be imposed, or other regulatory or governmental enforcement action could be taken, with respect to the Utility’s self-reports of noncompliance with natural gas safety regulations, investigations that were commenced after a pipeline explosion in Carmel, California on March 3, 2014, and other enforcement matters. See “Enforcement and Litigation Matters” in Note 13: Contingencies and Commitments of the Notes to the Consolidated Financial Statements in Item 8.

Diablo Canyon Power Plant

The Utility's Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act permit issued by the Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected.The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species.In January2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Utility's Diablo Canyon power plant's discharge was not protective of beneficial uses.

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In October2000, 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 $6million in environmental projects and future environmental monitoring related to coastal resources.On March21, 2003, the Central Coast Board voted to accept the settlement agreement.On June17, 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 July10, 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 January2005, 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 $30million.The Utility would seek to recover these costs through rates charged to customers.

The final requirements of the federal and state cooling water policies (discussed above in Item 1. Business under “Environmental Regulation – Water Quality”) could affect future negotiations between the Central Coast Board and the Utility regarding the status of the 2003 settlement agreement.  PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material impact on the Utility’s financial condition or results of operations.  

Venting Incidents in San Benito County

As part of its regular maintenance and inspection practices for its natural gas transmission system, the Utility performs in-line inspections of pipelines using devices called “pigs” that travel through the pipeline to inspect and clean the walls of the pipe.  When in-line inspections are performed, natural gas in the pipeline is released or vented at the pipeline station where the device is removed.  In February 2014, the Utility conducted an in-line inspection of a natural gas transmission pipeline that traverses San Benito County and vented the natural gas at the Utility’s transmission station located in Hollister, which is next to an elementary school.  The Utility vented the natural gas during school hours on three occasions that month.  After being informed of the venting by the local air district, the San Benito County District Attorney notified the Utility in December 2014 that it was contemplating bringing legal action against the Utility for violation of Health and Safety Code section 41700, which prohibits discharges of air contaminants that cause a public nuisance.  The Utility has been in settlement discussions with the district attorney’s office since that time.  On October 28,2015, the district attorney informed the Utility that it would seek civil penalties in excess of $100,000 but is willing to continue to explore settlement options with the Utility.

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.

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EXECUTIVE OFFICERS OF THE REGISTRANTS

The following individuals serve as executive officers (1) of PG&E Corporation and/or the Utility, as of February 18, 2016.  Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.

Name	Age	Positions Held Over Last Five Years	Time in Position
Anthony F. Earley, Jr.	66	Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation	September13, 2011 to present
		Executive Chairman of the Board, DTE Energy Company	October 1, 2010 to September 12, 2011
Nickolas Stavropoulos	57	President, Gas	September 15, 2015 to present
		President, Gas Operations	August 17, 2015 to September 15, 2015
		Executive Vice President, Gas Operations	June 13, 2011 to August 16, 2015
		Executive Vice President and Chief Operating Officer, U.S. Gas Distribution, National Grid	August 2007 to March 31, 2011
Geisha J. Williams	54	President, Electric	September 15, 2015 to present
		President, Electric Operations	August 17, 2015 to September 15, 2015
		Executive Vice President, Electric Operations	June 1, 2011 to August 16, 2015
		Senior Vice President, Energy Delivery	December 1, 2007 to May 31, 2011
Jason P. Wells	38	Senior Vice President and Chief Financial Officer, PG&E Corporation	January 1, 2016 to present
		Vice President, Business Finance	August 1, 2013 to December 31, 2015
		Vice President, Finance	October 1, 2011 to July 31, 2013
		Senior Director and Assistant Controller	November 1, 2008 to September 30, 2011
Dinyar B. Mistry	54	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
John R. Simon	51	Executive Vice President, Corporate Services and Human Resources, PG&E Corporation	August 17, 2015 to present
		Senior Vice President, Human Resources	April 16, 2007 to August 16, 2015
		Senior Vice President, Human Resources, PG&E Corporation	April 16, 2007 to August 16, 2015
Karen A. Austin	54	Senior Vice President and Chief Information Officer	June 1, 2011 to present
		President, Consumer Electronics, Sears Holdings	February 2009 to May 2011
Desmond A. Bell	53	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

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Helen A. Burt	59	Senior Vice President, External Affairs and Public Policy, PG&E Corporation	September 30, 2015 to present
		Senior Vice President, Corporate Affairs	September 18, 2014 to September 30, 2015
		Senior Vice President, Corporate Affairs, PG&E Corporation	September 18, 2014 to September 30, 2015
		Senior Vice President and Chief Customer Officer	February 27, 2006 to September 17, 2014
Loraine M. Giammona	48	Senior Vice President and Chief Customer Officer	September 18, 2014 to present
		Vice President, Customer Service	January 23, 2012 to September 17, 2014
		Regional Vice President, Customer Care, Comcast Cable	November 2002 to January 2012
Edward D. Halpin	54	Senior Vice President, Power Generation and Chief Nuclear Officer	September 8, 2015 to present
		Senior Vice President and Chief Nuclear Officer	April 2, 2012 to September 8, 2015
		President, Chief Executive Officer and Chief Nuclear Officer, South Texas Project Nuclear Operating Company	December 2009 to March 2012
Kent M. Harvey	57	Senior Vice President, Finance, PG&E Corporation	January 1, 2016 to present
		Senior Vice President and Chief Financial Officer, PG&E Corporation	August 1, 2009 to December 31, 2015
		Senior Vice President, Financial Services	August 1, 2009 to August 17, 2015
Julie M. Kane	57	Senior Vice President and Chief Ethics and Compliance Officer	May 18, 2015 to present
		Vice President, General Counsel and Compliance Officer, North America and Corporate Functions, and Compliance Officer, North America, Avon Products, Inc.	September 30, 2013 to March 31, 2015
		Vice President, Ethics and Compliance, Novartis Corporation	January 1, 2010 to August 31, 2013
Gregory K. Kiraly	51	Senior Vice President, Electric Transmission and Distribution	September 8, 2015 to present
		Senior Vice President, Electric Distribution Operations	September 18, 2012 to September 8, 2015
		Vice President, Electric Distribution Operations	October 1, 2011 to September 17, 2012
		Vice President, SmartMeter Operations	August 23, 2010 to September 30, 2011
Steven E. Malnight	43	Senior Vice President, Regulatory Affairs	September 18, 2014 to present
		Vice President, Customer Energy Solutions	May 15, 2011 to September 17, 2014
		Vice President, Integrated Demand Side Management	July 1, 2010 to May 14, 2011

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Hyun Park	54	Senior Vice President and General Counsel, PG&E Corporation	November13, 2006 to present
Jesus Soto, Jr.	48	Senior Vice President, Gas Operations	September 8, 2015 to present
		Senior Vice President, Engineering, Construction and Operations	September 16, 2013 to September 8, 2015
		Senior Vice President, Gas Transmission Operations	May 29, 2012 to September 15, 2013
		Vice President, Operations Services, El Paso Pipeline Group	May 2007 to May 2012
Fong Wan	54	Senior Vice President, Energy Policy and Procurement	September 8, 2015 to present
		Senior Vice President, Energy Procurement	October 1, 2008 to September 8, 2015

(1)Mr. Earley, Mr. Stavropoulos, Ms. Williams, Mr. Simon, Ms. Burt, Ms. Kane, Mr. Park, and Mr. Wells are executive officers of both PG&E Corporation and the Utility.  Mr. Harvey is an executive officer of PG&E Corporation only.  All other listed officers are executive officers of the Utility only.

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

As of February 12, 2016, there were 59,317 holders of record of PG&E Corporation common stock.  PG&E Corporation common stock is listed on the New York 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 in the table entitled “Quarterly Consolidated Financial Data (Unaudited)” which appears after the Notes to the Consolidated Financial Statements in Item 8.Shares of common stock of the Utility are wholly owned by PG&E Corporation.  Information about the frequency and amount of dividends on common stock declared by PG&E Corporation and the Utility for the two most recent fiscal years and information about the restrictions upon the payment of dividends on their common stock Utility appears in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 5 of the Notes to the Consolidated Financial Statementsin Item 8 and in “Liquidity and Financial Resources –Dividends” in Item 7 below.

Sales of Unregistered Equity Securities

PG&E Corporation made equity contributions to the Utility totaling $100 million during the quarter ended December 31, 2015.  PG&E Corporation did not make any sales of unregistered equity securities during 2015 in reliance on an exemption from registration under the Securities Act of 1933, as amended.  However, PG&E Corporation recently discovered, based on a review of new accounts opened under its Dividend Reinvestment and Stock Purchase Plan ("DRSPP") since 2013, that it issued and sold shares of common stock under the optional cash purchase feature of its DRSPP more than three years after the related registration statement for the DRSPP became effective, including approximately 19,550 shares for estimated aggregate sales proceeds of $1 million during the year ended December 31, 2015.  As a result, participants who purchased these shares may have a rescission right that would allow them to return the shares to PG&E Corporation in exchange for the purchase price paid by such participants, plus interest, less the value of dividends received. 

Issuer Purchases of Equity Securities

During the quarter ended December 31, 2015, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding.Also, during the quarter ended December 31, 2015, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

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ITEM 6. SELECTED FINANCIAL DATA

(in millions, except per share amounts)	2015		2014		2013		2012		2011
PG&E Corporation
For the Year
Operating revenues	$	16,833	$	17,090	$	15,598	$	15,040	$	14,956
Operating income		1,508		2,450		1,762		1,693		1,942
Net income		888		1,450		828		830		858
Net earnings per common share, basic (1)		1.81		3.07		1.83		1.92		2.10
Net earnings per common share, diluted		1.79		3.06		1.83		1.92		2.10
Dividends declared per common share (2)		1.82		1.82		1.82		1.82		1.82
At Year-End
Common stock price per share	$	53.19	$	53.24	$	40.28	$	40.18	$	41.22
Total assets		63,339		60,127		55,605		52,449		49,750
Long-term debt (excluding current portion)		16,030		15,050		12,717		12,517		11,766
Capital lease obligations (excluding current
portion) (3)		49		69		90		113		212
Pacific Gas and Electric Company
For the Year
Operating revenues	$	16,833	$	17,088	$	15,593	$	15,035	$	14,951
Operating income		1,511		2,452		1,790		1,695		1,944
Income available for common stock		848		1,419		852		797		831
At Year-End
Total assets		63,140		59,865		55,049		51,923		49,242
Long-term debt (excluding current portion)		15,680		14,700		12,717		12,167		11,417
Capital lease obligations (excluding current
portion) (3)		49		69		90		113		212

(1) See “Summary of Changes in Net Income and Earnings per Share” in Item 7. MD&A.

(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” in MD&A in Item 7 and in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 5 in Item 8.

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

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ANDRESULTS OF OPERATIONS

OVERVIEW

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, 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’s base revenue requirements are set by the CPUC in its GRC and GT&S rate case and by the FERC in its TO rate cases based on forecast costs.Differences between forecast costs and actual costs can occur for numerous reasons, including the volume of work required and the impact of market forces on the cost of labor and materials.Differences in costs can also arise from changes in laws and regulations at both the state and federal level.Generally, differences between actual costs and forecast costs could affect the Utility’s ability to earn its authorized return (referred to as “Utility Revenues and Costs that Impacted Earnings” in Results of Operations below).However, for certain operating costs, such as costs associated with pension and other employee benefits, the Utility is authorized to track the difference between actual amounts and forecast amounts and recover or refund the difference through rates (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Results of Operations below).The Utility also collects revenue requirements to recover certain costs that the CPUC has authorized the Utility to pass on to customers, such as the costs to procure electricity or natural gas for its customers.Therefore, although these costs can fluctuate, they generally do not impact net income (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Results of Operations below).See “Ratemaking Mechanisms” in Item 1 for further discussion.

This is a combined report of PG&E Corporation and the Utility, and includes separate Consolidated Financial Statements for each of these two entities.  This combined MD&A should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in Item 8. 

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Summary of Changes in Net Income and Earnings per Share

The following table is a summary reconciliation of the key changes, after-tax, in PG&E Corporation’s income available for common shareholders and EPS (as well as earnings from operations and EPS based on earnings from operations)for the year ended December 31, 2015 compared to the year ended December 31, 2014 (see “Results of Operations” below).“Earnings from operations” is a non-GAAP financial measure and is calculated as income available for common shareholders less items impacting comparability.“Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods.PG&E Corporation uses earnings from operations to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short- and long-term operating plans, and employee incentive compensation.PG&E Corporation believes that earnings from operations provide additional insight into the underlying trends of the business allowing for a better comparison against historical results and expectations for future performance.  Earnings from operations are not a substitute or alternative for GAAP measures such as income available for common shareholders and may not be comparable to similarly titled measures used by other companies.

			EPS
(in millions, except per share amounts)	Earnings		(diluted)
Income Available for Common Shareholders - 2014	$	1,436	$	3.06
Natural gas matters (1)		216		0.45
Environmental-related costs (2)		(4)		(0.01)
Earnings from Operations - 2014 (3)	$	1,648	$	3.50
Growth in rate base earnings		105		0.22
Timing of 2015 GT&S cost recovery (4)		(208)		(0.43)
Regulatory and legal matters (5)		(16)		(0.04)
Gain on disposition of SolarCity stock (6)		(13)		(0.03)
Increase in shares outstanding		-		(0.12)
Miscellaneous		3		0.02
Earnings from Operations - 2015 (3)	$	1,519	$	3.12
Insurance recoveries (7)		29		0.06
Fines and penalties (8)		(578)		(1.19)
Pipeline-related expenses (9)		(61)		(0.13)
Legal and regulatory related expenses (9)		(35)		(0.07)
Income Available for Common Shareholders - 2015	$	874	$	1.79

(1)  In 2014, natural gas matters included pipeline-related costs to perform work under the PSEP and other activities associated with safety improvements to the Utility’s natural gas system, as well as legal and other costs related to natural gas matters. Natural gas matters also included charges related to fines, third party liability claims, and insurance recoveries in 2014.

(2)In 2014, the Utility reduced its accrual related to the Hinkley whole house water replacement program.

(3)  “Earnings from operations” is not calculated in accordance with GAAP and excludes the items impacting comparability shown in notes (1) and (2) above and Notes (7), (8), and (9) below.

(4)Represents expenses during the year ended December 31, 2015 as compared to 2014, with no corresponding increase in revenue.  The Utility has requested that the CPUC authorize an increase to the Utility’s revenue requirements for 2015, 2016, and 2017 in its 2015 GT&S rate case, and expects a final decision in 2016.  Any revenue requirement increase that the CPUC may authorize would be retroactive to January 1, 2015but would be recorded in the period a final decision is issued.

(5)Includes legal and other regulatory related costs that were partially offset by incentive revenues.

(6) Represents the larger gain recognized during the year ended December 31, 2014 as compared to 2015.

(7)Represents insurance recoveries of $49 million, pre-tax, for third party claims and associated legal costs related to the San Bruno accident the Utility received during the year ended December 31, 2015.  The Utility has received a cumulative total of $515 million through insurance related to $558 million of third-party claims and $92 million of legal costs incurred. No further insurance recoveries related to these claims and costs are expected.

(8)Represents the impact of the Penalty Decision (see Note 13 of the Notes to the Consolidated Financial Statements in Item 8. for before-tax amounts). 

(9) In 2015, pipeline-related expenses include costs incurred to identify and remove encroachments from transmission pipeline rights of way and to performremaining work under the Utility’s PSEP.  Legal and regulatory related expenses include costs incurred in connection with various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

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Key Factors Affecting Results of Operations, Financial Condition, and Cash Flows

PG&E Corporation and the Utility believe that their future results of operations, financial condition, and cash flows will be materially affected by the following factors: 

· The Outcome of Enforcement and Litigation Matters.Future financial results will be impacted by the unrecoverable pipeline safety-related and remedies costs required by the Penalty Decision. The Utility’s future results may also be impacted by various other pending enforcement and regulatory actions, including the federal criminal charges and CPUC investigations of the Utility’s compliance with natural gas distribution record-keeping practices and potential violations of the CPUC’s ex parte communication rules.  (See “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

· The Timing and Outcome of Regulatory Matters.  The 2015 GT&S rate case remains pending.  The Utility requested that the CPUC authorize a $532 million increase in annualrevenue requirements for gas transmission and storage operations beginning on January 1, 2015 with attrition increases in 2016 and 2017.  Any revenue requirement increase that the CPUC may authorize would be retroactive to January 1, 2015 but would be recorded in the period a final decision is reached.(See “Regulatory Matters −2015 Gas Transmission and Storage Rate Case” below for more information.)In September 2015, the Utility filed its 2017 GRC application to request that the CPUC authorize revenue requirements for the Utility’s electric generation business and its electric and natural gas distribution business for 2017 through 2019.  (See “Regulatory Matters −2017 General Rate Case” below for more information.)  In addition, the Utility has one transmission owner rate case pending at the FERC (See “Regulatory Matters – FERC TO Rate Cases” below.)The outcome of regulatory proceedings can be affected by many factors, including the level of opposition by intervening parties, potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors.

· The Ability of the Utility to Control Operating Costs and Capital Expenditures.Whether the Utility is able to earn its authorized rate of return could be materially affected if the Utility’s actual costs differ from the amounts authorized in the rate case decisions.In addition to incurring shareholder-funded costs and costs associated with remedial measures required by the Penalty Decision, the Utility also forecasts that in 2016 it will incur unrecovered pipeline-related expenses ranging from $100 million to $150 million which primarily relate to costs to identify and remove encroachments from transmission pipeline rights-of-way. The ultimate amount of unrecovered costs also could be affected by how the CPUC determines which costs are included in determining whether the $850 million shareholder-funded obligation under the Penalty Decision has been met, and the outcome of pending and future investigations and enforcement matters.  (See  “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)The Utility’s ability to recover costs in the future also could be affected by decreases in customer demand driven by legislative and regulatory initiatives relating to distributed generation resources, renewable energy requirements, and changes in the electric rate structure.

· The Amount and Timing of the Utility’s Financing Needs.  PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure.  In 2015, PG&E Corporation issued $801million of common stock with cash proceeds and made equity contributions to the Utility of $705 million.  PG&E Corporation forecasts that it will issue a material amount of equity in 2016 and future years to support the Utility’s capital expenditures.  PG&E Corporation will issue additional equity to fund charges incurred by the Utility to comply with the Penalty Decision, to fund unrecoverable pipeline-related expenses, and to pay fines and penalties that may be required by the final outcomes of pending enforcement matters.These additional issuances would have a material dilutive impact on PG&E Corporation’s EPS.  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 the outcome of the matters discussed in “Enforcement and Litigation Matters” in Note 13of the Notes to the Consolidated Financial Statements in Item 8, Financial Statements and Supplementary Data,changes in their respective credit ratings, general economic and market conditions, and other factors.

For more information about the factors and risks that could affect PG&E Corporation’s and the Utility’s future results of operations, financial condition, and cash flows, or that could cause future results to differ from historical results, see Item 1A. Risk Factors.  In addition, this 2015Form 10-K contains forward-looking statements that are necessarily subject to various risks and uncertainties.  These statements reflect management’s judgment and opinions that 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.  See the section entitled “Cautionary Language Regarding Forward-Looking Statements” below for a list of some of the factors that may cause actual results to differ materially.  PG&E Corporation and the Utility are not able to predict all the factors that may affect future results.  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 following discussion presents PG&E Corporation’s and the Utility’s operating results for2015, 2014, and 2013.  See “Key Factors Affecting Results of Operations, Financial Condition, and Cash Flows” above for further discussion about factors that could affect future results of operations.

PG&E Corporation

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below.  The following table provides a summary of net income (loss) available for common shareholders:

(in millions)	2015		2014		2013
Consolidated Total	$	874	$	1,436	$	814
PG&E Corporation		26		17		(38)
Utility	$	848	$	1,419	$	852

PG&E Corporation’s net income or loss consists primarily of interest expense on long-term debt, other income or loss from investments, and income taxes.  Results include approximately $30 million and $45 million of realized gains and associated tax benefits related to an investment in SolarCity Corporation recognized in 2015 and 2014, respectively.PG&E Corporation’s operating results in 2013 reflected an impairment loss of $29 million related to tax equity fund investments.

Utility

The table below shows certain items from the Utility’s Consolidated Statements of Income for 2015, 2014,and 2013.  The table separately identifies the revenues and costs that impacted earnings from those that did not impact earnings.  In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs) and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings.  In addition, expenses that have been specifically authorized (such as the payment of pension costs) and the corresponding revenues the Utility is authorized to collect to recover such costs, do not impact earnings.

Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility’s costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on rate base.  Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets.

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The Utility’s operating results for 2015 reflect charges associated with the impact of the Penalty Decision.  (See “Utility Revenues and Costs that Impacted Earnings” below.)

	2015						2014						2013
	Revenues and Costs:						Revenues and Costs:						Revenues and Costs:
(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	$	7,442	$	6,215	$	13,657	$	7,059	$	6,597	$	13,656	$	6,465	$	6,024	$	12,489
Natural gas operating revenues		2,082		1,094		3,176		2,072		1,360		3,432		1,776		1,328		3,104
Total operating revenues		9,524		7,309		16,833		9,131		7,957		17,088		8,241		7,352		15,593
Cost of electricity		-		5,099		5,099		-		5,615		5,615		-		5,016		5,016
Cost of natural gas		-		663		663		-		954		954		-		968		968
Operating and maintenance		5,402		1,547		6,949		4,247		1,388		5,635		4,374		1,368		5,742
Depreciation, amortization, and decommissioning		2,611		-		2,611		2,432		-		2,432		2,077		-		2,077
Total operating expenses		8,013		7,309		15,322		6,679		7,957		14,636		6,451		7,352		13,803
Operating income		1,511		-		1,511		2,452		-		2,452		1,790		-		1,790
Interest income (1)						8						8						8
Interest expense (1)						(763)						(720)						(690)
Other income, net (1)						87						77						84
Income before income taxes						843						1,817						1,192
Income tax (benefit) provision (1)						(19)						384						326
Net income						862						1,433						866
Preferred stock dividend requirement (1)						14						14						14
Income Available for Common Stock					$	848					$	1,419					$	852

(1) These items impacted earnings.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for 2015, 2014, and 2013, focusing on revenues and expenses that impacted earnings for these periods.

Operating Revenues

The Utility’s electric and natural gas operating revenues increased $393million or 4% in 2015 compared to 2014, primarily a result of approximately $490 million of additional base revenues as authorized by the CPUC in the 2014 GRC decision and by the FERC in the TO rate case.This increase was partially offset by the absence of approximately $110 million of revenues the CPUC authorized the Utility to collect for recovery of certain PSEP-related costs during the same period in 2014.

The Utility’s electric and natural gas operating revenues that impacted earnings increased $890 million or 11% in 2014 compared to 2013.  This amount includedan increase to base revenues of $460 million as authorized by the CPUC in the 2014 GRC decision. The GRC decision also resulted in higher base revenues of $150 million in 2014 related primarily to the DOE settlement for spent nuclear fuel storage costs. The total increase in operating revenues included approximately $150 million of PSEP-related revenues, and revenues authorized by the FERC in the TO rate case, as well as revenues authorized by the CPUC for recovery of nuclear decommissioning costs.  The Utility also collected higher gas transmission revenues driven by increased demand for gas-fired generation.

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Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings increased $1.2 billion or 27% in 2015 compared to 2014, primarily due to $907 million in charges associated with the Penalty Decision, consisting of $400 million for the customer bill credit, an additional $100 million charge for the fine payable to the state, and $407 million of disallowed capital charges. (See“Enforcement and Litigation Matters” inNote 13 of the Notes to the Consolidated Financial Statements in Item 8.)  The increase is also due to higher labor and benefit-related expenses of approximately $100 million and fewer insurance recoveriesfor third-party claims and associated legal costs of $63 million related to the San Bruno accident.  No further insurance recoveries related to these claims are expected.  These increases were offset by $116 million in disallowed capital recorded in 2014 related to the PSEP. 

The Utility’s operating and maintenance expenses that impacted earnings decreased $127 million or 3% in 2014 compared to 2013, primarily due to lower third-party claims and associated legal costs of $117 million resulting from the settlement of all outstanding third-party claims, lower disallowed capital expenditures of $80 million and lower insurance recoveries for third-party claims and associated legal costs of $42 million related to the San Bruno accident. These decreases were offset by higher benefit-related expenses and other operating expenses of $120 million in 2014 as compared to 2013. 

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses increased $179 million or 7% in 2015 compared to 2014 and $355 million or 17% in 2014 compared to 2013.  In 2015, the increase was primarily due to the impact of capital additions and higher depreciation rates as authorized by the FERC in the TO rate case.  In 2014, the increase was primarily due to higher depreciation rates as authorized by the CPUC in the 2014 GRC decision and higher nuclear decommissioning expense reflecting the year-to-date increase as authorized by the CPUC in the nuclear decommissioning triennial proceeding.Additionally, depreciation, amortization, and decommissioning expenses were impacted by an increase in capital additions during 2014 as compared to 2013.

Interest Expense

The Utility’s interest expenses increased by $43 million in the year ended December 31, 2015 compared to the same period in 2014, primarily due to the issuance of additional long-term debt.  There were no material changes to interest expense in the year ended December 31, 2014 compared to the same period in 2013.

Interest Income and Other Income, Net

There were no material changes to interest income and other income, net for the periods presented.

Income Tax Provision

The Utility’s revenue requirements for the 2014 GRC decision period reflects flow-through ratemaking for income tax expense benefits attributable to the accelerated recognition of repair costs and certain other property-related costs for federal tax purposes.  PG&E Corporation and the Utility’s effective tax rates for 2015 are lower as compared to 2014 and for 2014 as compared to 2013 and are expected to remain lower than the statutory rate in 2016 due to these temporary differences.

The Utility’s income tax provision decreased $403million or 105% in 2015as compared to 2014.  This is primarily the result of the statutory tax effect, $397 million, of the lower income before income taxes in 2015 as compared to 2014.  The lower effective tax rate is the result of the tax benefits from property-related timing differences applied to this lower income before income taxes.

The Utility’s income tax provision increased$58 million or 18% in 2014 as compared to 2013 primarily due to higher income before income taxes, partially offset by certain reductions in tax expense for flow-through treatment as discussed above.

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The following table reconciles the income tax expense at the federal statutory rate to the income tax provision:

	2015		2014		2013
Federal statutory income tax rate	35.0	%	35.0	%	35.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	(4.8)		1.6		(2.2)
Effect of regulatory treatment of fixed asset differences (2)	(33.7)		(14.7)		(3.8)
Tax credits	(1.3)		(0.7)		(0.4)
Benefit of loss carryback	(1.5)		(0.8)		(1.0)
Non-deductible penalties (3)	4.3		0.3		0.7
Other, net	(0.2)		0.4		(0.9)
Effective tax rate	(2.2)	%	21.1	%	27.4	%

(1)Includes the effect of state flow-through ratemaking treatment.  In 2015, amounts reflect an agreement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions.   

(2)Includes the effect of federal flow-through ratemaking treatment for certain property-related costsin 2015 and 2014 as authorized by the 2014 GRC decision.  Amounts are impacted by the level of income before income taxes. 

(3)Represents the effects of non-tax deductible fines and penalties associated with the Penalty Decision.For more information about the Penalty Decision see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

Utility Revenues and Costs that did not Impact Earnings

Fluctuations in revenues that did not impact earnings are primarily driven by procurement costs, see below for more detail.

Cost of Electricity

TheUtility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities.  (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8.) 

(in millions)	2015		2014		2013
Cost of purchased power (1)	$	4,805	$	5,266	$	4,696
Fuel used in own generation facilities		294		349		320
Total cost of electricity	$	5,099	$	5,615	$	5,016
Average cost of purchased power per kWh	$	0.100	$	0.101	$	0.094
Total purchased power (in millions of kWh) (2)		48,175		52,008		49,941

(1) Cost of purchased power was impacted primarily by a decline in the market price of natural gasin 2015 compared to 2014.

(2)The decrease in purchased power resulted from an increase in generation from the Utility’s own generation facilities.  Gas-firedand nuclear generation increased during the year ended December 31, 2015 as compared to the same periods in 2014.

The Utility’s total purchased power is driven by customer demand, the availability of the Utility’s own generation facilities (including the Diablo Canyon nuclear generation power plant and hydroelectric plants), and the cost-effectiveness of each source of electricity.

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Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of procurement, storage, transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities.  (See Note 9 of the Notes to the Consolidated Financial Statements in Item 8.)  The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of storage and transportation, and changes in customer demand.

(in millions)	2015		2014		2013
Cost of natural gas sold	$	518	$	813	$	807
Transportation cost of natural gas sold		145		141		161
Total cost of natural gas	$	663	$	954	$	968
Average cost per Mcf (1) of natural gas sold (2)	$	2.74	$	4.37	$	3.54
Total natural gas sold (in millions of Mcf)		189		186		228
(1) One thousand cubic feet

(2) Average cost of natural gas sold impacted primarily by a decline in the market price of natural gas in 2015 compared to 2014.

Operating and Maintenance Expenses

The Utility’s operating expenses that did not impact earnings include certain costs that the Utility is authorized to recover as incurred such as pension contributions and public purpose programs costs.  If the Utility were to spend more than authorized amounts, these expenses could have an impact to earnings.  For 2015, 2014, and 2013, no material amounts were incurred above authorized amounts.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations, finance capital expenditures, 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 CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect related to its financing costs. The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% equity and 48% debt and preferred stock.  (See “Ratemaking Mechanisms” in Item 1).  The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs. 

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, 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 hasmaterial stand-alone cash flows related tothe issuance of equity and long-term debt, dividend payments, and borrowings and repayments under its revolving credit facility.  PG&E Corporation relies on short-term debt, including commercial paper, to fund temporary financing needs.

PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of the pending enforcement and litigation matters.  Credit rating downgrades may increase the cost and availability of short-term borrowing, including commercial paper, the costs associated with credit facilities, and long-term debt costs.  In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability positions.  (See Note 9 of the Notes to the Consolidated Financial Statements in Item 8.) 

PG&E Corporation’s equity contributions to the Utility are funded primarily through common stock issuances.  PG&E Corporation forecasts that it will issue between $600 million and $800 million in common stock during 2016, primarily to fund equity contributions to the Utility.  The Utility’s future equity needs will continue to be affected by charges incurred to comply with the Penalty Decision, by unrecoverablepipeline-related expenses, and by fines and penalties that may be imposed in connection with thematters described in “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8 below.Common stock issuances by PG&E Corporation to fund these needs would have a material dilutive impact on PG&E Corporation’s EPS.

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Cash and Cash Equivalents

PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds.  In addition to cash and cash equivalents, the Utility holds 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.  (See “Resolution of Remaining Chapter 11 Disputed Claims” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)  The Utility is uncertain when and how the remaining disputed claims will be resolved.

Financial Resources

Debt and Equity Financings

The Utility issued $1.15 billion in long-term debt during the year ended December 31, 2015.  (See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.)   

In February 2015, PG&E Corporation entered into a new equity distribution agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $500 million.  During 2015, PG&E Corporation sold   1.4 million sharesof common stock under this agreement for cash proceeds of $74 million, net of commissions paid of $1 million.

In August 2015, PG&E Corporation sold 6.8 million shares of its common stock in an underwritten public offering for cash proceeds of $352 million, net of fees.

In addition,during 2015, PG&E Corporation sold 7.9 million shares of common stock under its 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plansfor total cash proceeds of $354 million.

The proceeds from equity issuances were used for general corporate purposes, including the contribution of equity into the Utility.  For the year ended December 31, 2015, PG&E Corporation made equity contributions to the Utility of $705 million, of which $300 million was used to pay a fine to the State General Fund as required by the Penalty Decision.  Additionally, PG&E Corporation and the Utility expect to continue to issue long-term and short-term debt for general corporate purposes and to maintain the CPUC-authorized capital structure during 2016.

Revolving Credit Facilities and Commercial Paper Programs

At December 31, 2015, PG&E Corporation and the Utility had $300 million and $1.9 billion available under their respective $300 million and $3.0 billion revolving credit facilities.  (See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.)  

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.  At December 31, 2015, PG&E Corporation’s and the Utility’s total consolidated debt to total consolidated capitalization was 51% and 50%, respectively.  PG&E Corporation’s revolving credit facility agreement also requires that PG&E Corporation own, directly or indirectly, at least 80% of the outstanding common stock and at least 70% of the outstanding voting capital stock of the Utility.  In addition, the revolving credit facilities include usual and customary provisionsregarding events of default and covenants including covenants limiting liens to those permitted under PG&E Corporation’s and the Utility’s senior note indentures, mergers, and imposing conditions on the sale of all or substantially all of PG&E Corporation’s and the Utility’s assets and other fundamental changes.  At December 31, 2015, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

Dividends

PG&E Corporation

For each of the quarters in 2015, 2014, and 2013, the Board of Directors of PG&E Corporation declared common stock dividends of $0.455 per share, for annual dividends of $1.82 per share.  Dividends paid to common stockholders by PG&E Corporation were $856 million in 2015, $828 million in 2014, and $782 million in 2013.  In December 2015, the Board of Directors of PG&E Corporation declared quarterly dividends of $0.455 per share, totaling $224million, of which approximately $219 million was paid on January 15, 2016 to shareholders of record on December 31, 2015.

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Utility

For each of the quarters in 2015, 2014, and 2013, the Utility’s Board of Directors declared common stock dividends in the aggregate amount of $179 million to PG&E Corporation for annual dividends paid of $716 million in each of 2015, 2014, and 2013.  In addition, the Utility paid $14 million of dividends on preferred stock in each of 2015, 2014, and 2013.  The Utility’s preferred stock is cumulative and any dividends in arrears must be paid before the Utility may pay any common stock dividends.  In December 2015, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on February 15, 2016, to shareholders of record on January 29, 2016.

Utility Cash Flows

The Utility’s cash flows were as follows:

	Year Ended December 31,
(in millions)	2015		2014		2013
Net cash provided by operating activities	$	3,720	$	3,619	$	3,416
Net cash used in investing activities		(5,211)		(4,799)		(5,142)
Net cash provided by financing activities		1,495		1,170		1,597
Net change in cash and cash equivalents	$	4	$	(10)	$	(129)

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.  During 2015, net cash provided by operating activities increased by $101 million compared to 2014.  This increase was primarily due to higher base revenue collections authorized in the 2014 GRC and lower purchased power costs (see “Cost of Electricity” under “Results of Operations – Utility Revenues and Costs that did not Impact Earnings” above), offset by the payment of a $300 million fine to the State General Fund as required by the Penalty Decision.  During 2014, net cash provided by operating activities increased by $203 million compared to 2013.  This increase was primarily due to tax refunds received during 2014 compared to tax payments made during 2013 and additional collateral returned to the Utility in 2014 as compared to 2013, offset by higher purchased power costs (see “Cost of Electricity” under “Results of Operations – Utility Revenues and Costs that did not Impact Earnings” above).

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Future cash flow from operating activities will be affected by various factors, including:

• the shareholder-funded bill credit of $400 million to natural gas customers in 2016, as required by the Penalty Decision (see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements);

• the timing and amounts of other fines or penalties that may be imposed in connection with the criminal prosecution of the Utility and the remaining investigations and other enforcement matters (see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8 below);

• the timing and outcome of ratemaking proceedings, including the 2015 GT&S rate case;

• the timing and amount of costs the Utility incurs, but does not recover, associated with its natural gas system (including costs to implement remedial measures and $850 million to pay for designated pipeline safety projects and programs, as required by the Penalty Decision);

• the timing and amount of tax payments (including the bonus depreciation extension), tax refunds, net collateral payments, and interest payments;

• the timing of the resolution of the Chapter 11 disputed claims and the amount of principal and interest on these claims that the Utility will be required to pay.  

Investing Activities

Net cash used in investing activities increased by $412 million during 2015 as compared to 2014 primarily due to an increase of $340 million in capital expenditures and an increase in net purchases of nuclear decommissioning trust investments in 2015 as compared to net proceeds associated with sales of nuclear decommissioning trust investments in 2014.  Net cash used in investing activities decreased by $343 million during 2014 as compared to 2013 primarily due a decrease of $374 million in capital expenditures.  This decrease was primarily due to lower PSEP-related capital expenditures and the absence of additional investment in the Utility’s photovoltaic program.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.  The Utility estimates that it will incur between $5.4 billion and $5.6 billion in 2016. 

Financing Activities

During 2015, net cash provided by financing activities increased by$325 million as compared to 2014.  During 2014, net cash provided by financing activities decreased by $427 million as compared to 2013.  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, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date of existing debt instruments.  The Utility generally utilizes long-term 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.

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CONTRACTUAL COMMITMENTS

The following table provides information about PG&E Corporation’s and the Utility’s contractual commitments at December 31, 2015:

	Payment due by period
	Less Than		1-3		3-5		More Than
(in millions)	1 Year		Years		Years		5 Years		Total
Utility
Long-term debt (1):	$	917	$	2,991	$	2,888	$	22,150	$	28,946
Purchase obligations (2):
Power purchase agreements:		3,453		6,508		6,035		31,824		47,820
Natural gas supply, transportation, and storage		421		255		208		543		1,427
Nuclear fuel agreements		113		196		231		185		725
Pension and other benefits (3)		388		776		776		388		2,328
Operating leases (2)		40		81		76		195		392
Preferred dividends (4)		14		28		28		-		70
PG&E Corporation
Long-term debt (1):		8		16		351		-		375
Total Contractual Commitments	$	5,354	$	10,851	$	10,593	$	55,285	$	82,083

(1) Includes interest payments over the terms of the debt.  Interest is calculated using the applicable interest rate at December 31, 2015 and outstanding principal for each instrument with the terms ending at each instrument’s maturity.  (See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.) 

(2) See “Purchase Commitments” and “Other Commitments” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

(3) See Note 11 of the Notes to the Consolidated Financial Statements in Item 8. 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 shown in the column entitled “more than 5 years” represents only 1 year of contributions for the Utility’s pension and other benefit plans.

(4) Based on historical performance, it is assumed for purposes of the table above that dividends are payable within a fixed period of five years.

The contractual commitments table above 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 8 of the Notes to the Consolidated Financial Statements in Item 8.

Off-Balance Sheet Arrangements

PG&E Corporation and the Utility do not have anyoff-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 13 of the Notes to the Consolidated Financial Statements (the Utility’s commodity purchase agreements) in Item 8.

ENFORCEMENT AND LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Note 13 of the Notes to the Consolidated Financial Statements in Item 8. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s future financial results. 

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Department of Interior Inquiry

In September 2015, the Utility was notified that the U.S. Department of Interior (“DOI”) had initiated an inquiry into whether the Utility should be suspended or debarred from entering intofederal procurement and non-procurement contracts and programs citing the allegations contained in the superseding criminal indictment (See Note 13 in the Consolidated Financial Statements in Item 8). The Utility filed its initial response on November 2, 2015, to demonstrate that it is a presently responsible contractor under federal procurement regulations and that it believes suspension or debarment is not appropriate. It is uncertain when or if further action will be taken.

Pending Lawsuits and Claims

As of December 31, 2015, there were six purported derivative lawsuits seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims.

Four of the complaints were consolidated as the San Bruno Fire Derivative Cases and are pending in the Superior Court of California, County of San Mateo.  On August 28, 2015, the Superior Court overruled the demurrers filed by PG&E Corporation, the Utility and the individual director and officer defendants seeking to dismiss theSan Bruno Fire Derivative Cases, based upon the plaintiffs’ failure to demand action by the Boards of PG&E Corporation and the Utility prior to filing the complaint.  After the ruling, and pursuant to co-petitions for writ of mandate previously filed by PG&E Corporation, the Utility, and the individual defendants, on September 3, 2015 the California Court of Appeal issued an order staying the San Bruno Fire Derivative Cases pending the court’s final determination whether to stay the matter altogether until the resolution of federal criminal proceedings against the Utility.  On September 30, 2015, PG&E Corporation, the Utility, and the individual defendants filed an additional petition for writ of mandate asking the Court of Appeal to review the lower court’s August 28 decision overruling their demurrers.  On October 22, 2015, the Court of Appeal issued a ruling declining to review the August 28 decision.  On December 8, 2015, the Court of Appeal issued a writ of mandate to the Superior Court, ordering the Superior Court to stay all proceedings in the San Bruno Fire Derivative Cases “pending conclusion of the federal criminal proceedings” against the Utility.  The other two derivative actions are entitled Tellardin v. PG&E Corp. et. al., pending in the Superior Court of California, San Mateo County, and Iron Workers Mid-South Pension Fund v. Johns, et. al., pending in the United States District Court for the Northern District of California.  PG&E Corporation, and the other defendants have not answered or otherwise responded to the complaints in these actions.  In the Tellardin action, the defendants must answer or respond to the complaint 30 days after the stay in the San Bruno Fire Derivative Cases is lifted.  In the Iron Workers action, thecourt has not established a deadline by which the defendants must answer or respond.  Case management conferences have been scheduled in both actions (March 21, 2016 in the Tellardin action and June 3, 2016 in the Iron Workers action), after which PG&E Corporation will have more information about any further proceedings in these actions.

PG&E Corporation and the Utility are uncertain when and how the above lawsuits will be resolved.

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 financial condition, results of operations, and cash flows.

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2017 General Rate Case

On September 1, 2015, the Utility filed its 2017 GRC application with the CPUC. In the 2017 GRC, the Utility has requested that the CPUC determine the annual amount of base revenues (or “revenue requirements”) that the Utility will be authorized to collect from customers from 2017 through 2019 to recover its anticipated costs for electric distribution, natural gas distribution, and electric generation operations and to provide the Utility an opportunity to earn its authorized rate of return. (The Utility’s revenue requirements for other portions of its operations, such as electric transmission, natural gas transmission and storage services, and electricity and natural gas purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC.)  In its application, the Utility requested a revenue requirement increase of $457 million, as compared to authorized base revenues for 2016, as shown in the following tables:

						Increase
		Amounts		Amounts		Compared to
		Requested In		Currently		Currently
Line of Business:		the GRC		Authorized For		Authorized
(in millions)		Application		2016		Amounts
Electric distribution	$	4,376	$	4,212	$	164
Gas distribution		1,827		1,742		85
Electric generation		2,170		1,962		208
Total revenue requirements	$	8,373	$	7,916	$	457
Cost Category:
(in millions)
Operations and maintenance	$	1,833	$	1,664	$	169
Customer services		367		319		48
Administrative and general		978		1,011		(33)
Less: Revenue credits		(140)		(131)		(9)
Franchise fees, taxes other than income, and other adjustments		185		37		148
Depreciation (including costs of asset removal), return, and
income taxes		5,150		5,016		134
Total revenue requirements	$	8,373	$	7,916	$	457

In its application, the Utility stated that over the 2017-2019 GRC period the Utility plans to make average annual capital investments of approximately $4 billion in electric distribution, natural gas distribution and electric generation infrastructure, and to improve safety, reliability, and customer service. (These annual investments would be incremental to the Utility’s capital expenditures for electric and natural gas transmission infrastructure.) The Utility also requested that the CPUC establish a ratemaking mechanism that would increase the Utility’s authorized revenues in 2018 and 2019, 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 estimates that this mechanism would result in increases in revenue of $489 million in 2018 and an additional $390 million in 2019.

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In October 2015, the Utility filed supplemental testimony to reduce its original revenue requirement request by approximately $17 million per year based on its forecast that it will incur approximately $61 million for unrecoverable costs to implement the remedies ordered in the Penalty Decision.

On February 22, 2016 the Utility will file an update of its forecasted increase, primarily to reflect the impact of the recent five-year extension of the federal tax code provisions regarding bonus depreciation.

According to the CPUC’s current procedural schedule, testimony from the ORA and other parties is due in April 2016, evidentiary hearings are to be held this summer, followed by a proposed decision to be released in November 2016 and a final CPUC decision to be issued in December 2016.  The Utility has requested that the CPUC issue an order directing that the authorized revenue requirement changes be effective January 1, 2017, even if the final decision is issued after that date.

2015 Gas Transmission and Storage Rate Case

In the 2015 GT&S rate case, the Utility requested that the CPUC authorize a 2015 revenue requirement of $1.263 billion to recover anticipated costs of providing natural gas transmission and storage services, an increase of $532 million over currently authorized amounts. The Utility also requested attrition increases of $83 million in 2016 and $142 million in 2017. The Utility requested that the CPUC authorize the Utility’s forecast of its 2015 weighted average rate base for its gas transmission and storage business of $3.44 billion, which includes capital spending above authorized levels for the prior rate case period.

The ORA has recommended a 2015 revenue requirement of $1.044 billion, an increase of $329 million over authorized amounts.  TURN recommended that the Utility not recover costs associated with hydrostatic testing for pipeline segments placed in service after January 1, 1956, as well as certain other work that TURN considers to be remedial.TURN also recommended the disallowance of about $200 million of capital expenditures incurred over the period 2011 through 2014 and recommended that about $500 million of capital expenditures during this period be subject to a reasonableness review and an independent audit.TURN states that the Utility’s cost recovery should not begin until the CPUC issues a decision on the independent audit. On December 18, 2015, the ORA filed a motion in the 2015 GT&S rate case for an Order to Show Cause why the Utility should not be sanctioned $163 million for intentional misrepresentations regarding its compliance with gas safety regulations regarding maximum allowable operating pressure for its gas transmission lines. On December 30, 2015, the Utility filed a response to this motion stating that it does not believe there is merit to the allegations.ORA filed a reply on January 11, 2016, reiterating its allegations.

The Utility also has proposed changes to the revenue sharing mechanism authorized in the last GT&S rate case (covering 2011-2014) that subjected a portion of the Utility’s transportation and storage revenue requirement to market risk.The Utility proposed full balancing account treatment that allows for recovery of the Utility’s authorized transportation and storage revenue requirements (except for the revenue requirement associated with the Utility’s 25% interest in the Gill Ranch storage field).

Based on the scoping ruling and procedural schedule that was issued on June 11, 2015, the CPUC plans to issue an initial decision to authorize revenue requirements followed by a second decision to reduce the authorized revenue requirements by the costs of designated safety-related projects and programs up to the $850 million maximum cost disallowance imposed by the Penalty Decision. (See Note 13 in the Consolidated Financial Statements in Item 8 for more information about the CPUC’s Penalty Decision.) In accordance with an earlier CPUC decision regarding the Utility’s violation of the CPUC’s ex parte communication rules made in the GT&S rate case, the first decision could disallow the Utility from recovering up to a five-month portion of the revenue increase that may otherwise have been authorized.It is uncertain how much of the Utility’s costs to perform the safety-related projects and programs the CPUC will identify as counting toward the $850 million shareholder-funded obligation.If the Utility’s actual costs exceed costs that the CPUC counts towards the $850 million maximum, the Utility would record additional charges if such costs are not otherwise authorized by the CPUC.  Additionally, the Utility may record additional charges if the CPUC does not authorize capital spending from the prior rate case period. The authorized revenue requirements in the GT&S rate case would be retroactive to January 1, 2015.The ruling states that the case would be completed within 18 months of the date of the ruling, or by December 2016.

FERC TO Rate Cases

On September 30, 2015, the FERC approved a settlement that sets the Utility’s 2015 retail electric transmission revenue requirement at $1.201 billion, a $161 million increase over the currently authorized revenue requirement of $1.040 billion.

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On July 29, 2015, the Utility requested that the FERC approve a 2016 retail electric transmission revenue requirement of $1.515 billion. The proposed amount reflects a $314 million increase over the settled revenue requirement of $1.201 billion.  The Utility forecasts that it will make investments of $1.246 billion in 2016 in various capital projects.  The Utility’s forecasted rate base for 2016 is $5.85 billion, compared to forecasted rate base of $5.12 billion in 2015.  The Utility has requested that the FERC approve a 10.96% return on equity.  On September 30, 2015, the FERC accepted the proposed revenue requirement, subject to hearing and refund, and established March 1, 2016 as the effective date for rate changes. Hearings are being held in abeyance pending settlement discussions among the parties.

CPUC Investigation of the Utility’s Safety Culture

On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards. The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety incidents. The CPUC authorized the SED to engage a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s assessment.

The CPUC stated that the initial phase of the proceeding was categorized as rate setting because it will consider issues both of fact and policy and because the Utility and PG&E Corporation do not face the prospect of fines, penalties, or remedies in this phase. Upon completion of the consultant’s report, the assigned Commissioner will determine the scope of and next actions in the proceeding. The timing scope and potential outcome of the investigation are uncertain.

Diablo Canyon Nuclear Power Plant

The NRC operating licenses for the two nuclear generation units at Diablo Canyon expire in 2024 and 2025.  In November 2009, the Utility filed an application with the NRC to seek the renewal of the operating licenses, a process which can take several years.  After the March 2011 earthquake in Japan that damaged nuclear facilities, the NRC granted the Utility’s request to delay processing its renewal application until certain advanced seismic studies of the fault zones in the region surrounding Diablo Canyon were completed.  The seismic studies have been completed and in September 2014, the Utility submitted a report to the NRC and the CPUC’s Independent Peer Review Panel (“IPRP”) that confirmed the seismic safety of the plant.  The IPRP is providing comments on the report and the Utility expects the IPRP to conclude their review and issue a final report in 2016.  In addition, the Utility has requested that the California State Lands Commission extend the leases for the land occupied by Diablo Canyon’s water intake and discharge structures from the current expiration dates in 2018 and 2019 to 2024 and 2025 when the NRC operating licenses are currently due to expire.  The California State Lands Commission has deferred acting on the application until later in 2016.  It is uncertain whether the leases will be extended or whether an environmental review will be required before the commission can issue a decision. Finally, the California Water Board is not expected to issue a final decision before January 1, 2017 to address how the Utility’s nuclear operations at Diablo Canyon must comply with the state’s policy regarding once-through cooling.  The Utility’s Diablo Canyon operations must be in compliance with the California Water Board’s policy by December 31, 2024.  Based on these and other factors, the Utility is continuing to assess its strategy for license renewal of Diablo Canyon.  (See Item 1A. Risk Factors and “Environmental Regulation” in Item 1.  For a discussion of the Utility’s nuclear decommissioning obligations, see Note 2: Summary of Significant Accounting Policies – Asset Retirement Obligations of the Notes to the Consolidated Financial Statements in Item 8.)

LEGISLATIVE AND REGULATORY INITIATIVES

The California Legislature and the CPUC have adopted requirements and policies to accommodate the growth in distributed electric generation resources (including solar installations), increase the amount of renewable energy delivered to customers, foster the development of a state-wide electric vehicle charging infrastructure to encourage the use of electric vehicles, and promote customer energy efficiency and demand response programs. In addition, the CPUC continues to implement state law requirements to reform electric rates to more closely reflect the utilities’ actual costs of service, reduce cross-subsidization among customer rate classes, implement new rules and rates for net energy metering (which currently allow certain self-generating customers to receive bill credits for surplus power at the full retail rate), and allow customers to have greater control over their energy use. CPUC proceedings related to some of these matters are discussed below.

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In addition, prompted by a methane gas leak from a natural gas storage facility located in Southern California, the California Legislature has begun to consider adopting new legislation to address natural gas storage operations in California, including increased oversight of natural gas storage facilities and the adoption of new safety and reliability measures.  The California Governor also issued an emergency proclamation that requires various state agencies to take immediate action, as discussed below. 

The Utility’s ability to recover its costs, including investments associated with legislative and regulatory initiatives, as well as its electricity procurement and other operating costs, will, in large part, depend on the final form of legislative or regulatory requirements, and whether the associated ratemaking mechanisms can be timely adjusted to reflect changes in customer demand for the Utility’s electricity and natural gas service.

Natural Gas Storage Facilities

On January 6, 2016 the California Governor ordered the Division of Oil, Gas and Geothermal Resources (“DOGGR”) to issue emergency regulations to require gas storage facility operators throughout California, including the Utility, to comply with new safety and reliability measures, including minimum daily inspection of gas storage well heads (using gas leak detection technology such as infrared imaging), ongoing verification of the mechanical integrity of all gas storage wells, ongoing measurement of annular gas pressure or annular gas flow within wells, regular testing of all safety valves used in wells, establishing minimum and maximum pressure limits for each gas storage facility in the state, and establishing  a comprehensive risk management plan that evaluates and prepares for risks at each facility, including corrosion potential of pipes and equipment.The Utility may incur significant costs to comply with the new regulations but anticipates that it would be able to recover such costs through rates.  

The DOGGR, the CPUC, the CARB, and the CEC will be required to submit to the California Governor's Office a report that assesses the long-term viability of natural gas storage facilities in California.  The report will address operational safety and potential health risks, methane emissions, supply reliability for gas and electricity demand in California, and the role of storage facilities and natural gas infrastructure in the State's long-term GHG emission reduction strategies. 

New Renewable Energy Targets

In October 2015, the California Governor signed SB 350 which, effective January 1, 2016, increases the amount of renewable energy that must be delivered by most load-serving entities, including the Utility, to their customers from 33% of their total annual retail sales by the end of the 2017-2020 compliance period to 50% of their total annual retail sales by the end of the 2028- 2030 compliance period and in each compliance period thereafter.  SB 350 includes increasing interim renewable energy targets for the periods between 2020 and 2030 and continues to include compliance flexibility and waiver mechanisms, including increased flexibility to apply excess renewable energy procurement in one compliance period to future compliance periods.  The Utility will incur additional costs to procure renewable energy to meet the new renewable energy targets which the Utility expects will continue to be recoverable from customers as “pass-through” costs.  The Utility also may be subject to penalties for failure to meet the higher targets.  The CPUC is required to open a new rulemaking proceeding to adopt regulations to implement the higher targets.

Electric Distribution Resources Plan 

As required by California law, on July 1, 2015, the Utility filed its proposed electric distribution resources plan for approval by the CPUC. The Utility’s plan identifies optimal locations on its electric distribution system for deployment of distributed energy resources.  The Utility’s proposal is designed to allow energy technologies to be interconnected with each other and integrated into the larger grid while continuing to provide customers with safe, reliable and affordable electric service. The Utility envisions a future electric grid, titled the Grid of Things™, that would allow customers to choose new advanced energy supply technologies and services to meet their needs consistent with safe, reliable and affordable electric service.  The Utility’s 2017 GRC includes a request to recover some of the investment costs that it forecasts it will incur under its proposed electric distribution resources plan.

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Electric Rate Reform and Net Energy Metering (“NEM”)

On July 3, 2015, the CPUC approved a final decision to authorize the California investor–owned utilities to gradually flatten their tiered residential electric rate structures from four tiers to two tiers by January 1, 2019. The decision approved increased minimum bill charges for residential customers and also allows the imposition of a surcharge on customers with extremely high electricity use beginning in 2017. The decision requires the Utility to file a proposal by January 1, 2018, to charge residential electric customers based on time-of-use rates unless customers elect otherwise (known as “default time-of-use rates”). The Utility also may propose to impose a fixed charge on residential electric customers. Under the CPUC’s decision, default time-of-use rates must be implemented before the CPUC will permit the imposition of a fixed charge in electric rates.

In January 2016, the CPUC adopted new NEM rules and rates. The new rules and rates are expected to become effective for new NEM customers of the Utility later in 2016. New NEM customers will be required to pay an interconnection fee, will go on time of use rates, and will be required to pay non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay.

Electric Vehicle (EV) Infrastructure Development

In December 2014, the CPUC issued a decision adopting a policy to expand the California utilities’ role in developing an EV charging infrastructure to support California’s climate goals. On February 9, 2015, the Utility filed an application requesting that the CPUC approve the Utility’s proposal to deploy, own, and maintain more than 25,000 EV charging stations and the associated infrastructure.The Utility proposed to engage with third party EV equipment and service providers to operate and maintain the charging stations.  The Utility requested that the CPUC approve forecasted capital expenditures of $551 million over the 5 year deployment period.

On September 4, 2015, the assigned CPUC Commissioner and the ALJ issued a scoping memo and procedural schedule that required the Utility to supplement its application by submitting a more phased deployment approach that will be considered in a first phase of the proceeding. On October 12, 2015, the Utility submitted supplemental testimony presenting two separate proposals.  In its first proposal, the Utility has requested that the CPUC approve approximately $70 million in capital expenditures to deploy and own 2,510 EV charging stations over approximately 2 years.In its second proposal, the Utility has requested that the CPUC approve approximately $187 million in capital expenditures to deploy and own 7,530 EV charging stations over approximately 3 years. Under the CPUC’s schedule, a proposed decision for the first phase of the proceeding is expected to be issued by June 2016. Further deployment of EV charging stations would be considered in a second phase of the proceeding depending on the outcome of the first phase.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public.  These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous wastes; the reporting and reduction of CO2 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.  (See Item 1A. Risk Factors and “Environmental Regulation” in Item 1.)

Natural Gas Compressor Station 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 stations. The Utility is also required to take measures to abate the effects of the contamination on the environment. At December 31,2015, $140 million and $300 million was accrued in the Consolidated Balances Sheets for estimated undiscounted remediation costs associated with the Hinkley site and the Topock site, respectively.  Costs associated with the Hinkley site are not recovered through rates.  (See “Environmental Remediation Contingencies” in Note 13 of the Notes to theConsolidated Financial Statements in Item 8.)

RISK MANAGEMENT ACTIVITIES

The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit.

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-speculative purposes (i.e., risk mitigation).  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.

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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 current authorized revenue requirement for natural gas transportation and storage service to non-core customers is not balancing account protected.The Utility recovers these costs through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. (See “2015 Gas Transmission and Storage Rate Case” above.)

The Utility uses value-at-risk to measure its shareholders’ exposure to these risks. The Utility’s value-at-risk was approximately $2 million and $1 million at December 31, 2015 and 2014, respectively.  During 2015, the Utility’s approximate high, low, and average values-at-risk were $2 million, $1 million and $2 million, respectively. During 2014, the value-at-risk amounts were $9 million, $1 million and $5 million, respectively.  (See Note 9 of the Notes to the Consolidated Financial Statements in Item 8 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.  AtDecember 31, 2015 and 2014, if interest rates changed by 1% for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the impact on net income over the next 12 months would be $11million and $9 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding.(See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates.)

Energy Procurement Credit Risk

The Utility conducts business with counterparties mainly in the energy industry, including the CAISO market, other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, electricity generation companies, 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 executes many energy contracts under 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.

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The following table summarizes the Utility’s energy procurement credit risk exposure to its counterparties:

									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, 2015	$	64	$	(11)	$	53		4		39
December 31, 2014		88	$	(18)	$	70		3		29

(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 posted by counterparties and held by the Utility).  For purposes of this table, parental guarantees are not included as part of the calculation.

CRITICAL ACCOUNTING POLICIES

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

Regulatory Accounting

As a regulated entity, the Utility records regulatory assets and liabilities for amounts that are deemed probable of recovery from, or refund to, customers. These amounts would otherwise be recorded to expense or income under GAAP.  Refer to “Regulation and Regulated Operations” in Note 2 as well as Note 3of the Notes to the Consolidated Financial Statements in Item 8.  At December 31, 2015, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $9.3billion and regulatory liabilities (including current balancing accounts payable) of $7.7 billion.

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 the recovery of any material costs previously recognized by the Utility as regulatory assets for the periods presented.  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.  If regulatory accounting did not apply, the Utility’s future financial results could become more volatile as compared to historical financial results due to the differences in the timing of expense or revenue recognition.

In addition, regulatory accounting standards require recognition of aloss if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered. The Utility records a provision based on its best estimate; to the extent there is a high degree of uncertainty in the Utility’s forecast, it will record a provision based on the lower end of the range of possible losses. The Utility’s capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors. The Utility recorded charges of $407 million in 2015 for estimated capital spending that is probable of disallowance related to the Penalty Decision.  Management will continue to evaluate and estimate capital spending that may be probable of disallowance in future periods.  These estimates are subject to adjustment based on the final 2015 GT&S rate case decision which is expected in 2016.  The Utility also recorded $116 million and $196 million in 2014 and 2013, respectively, for PSEP capital costs that are expected to exceed the amount to be recovered. See “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.  Management will continue to periodically assess its safety-related capital costs and the related CPUC regulatory proceedings, and further charges could be required in future periods.

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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 manufactured gas plant 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 manufactured gas plant 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, 2015 and 2014, the Utility’s accruals for undiscounted gross environmental liabilities were $969million and $954 million, respectively.  The Utility’s undiscounted future costs could increase to as much as $1.9billion 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, are named as parties in a number of claims and lawsuits.  In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations.PG&E Corporation and the Utility record a provision for a loss contingency 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.  The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costsfrom the provision for loss and expense these costs as incurred.  (See “Enforcement and Litigation Matters” and “Legal and Regulatory Contingencies” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

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Asset Retirement Obligations

PG&E Corporation and the Utility account for an 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.  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.  (See Notes 2 and 3 of the Notes to the Consolidated Financial Statements in Item 8.)

To estimate its 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. 

At December 31, 2015, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was $3.6 billion.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.  If the inflation adjustment or discount rate increased 25 basis points, the result would be an immaterial impact to ARO. 

Pension and Other Postretirement Benefit Plans

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees as well as contributory postretirement health care and medical plans for eligibleretirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.  Adjustments to the pension and other benefit obligation are based on the differences between actuarial assumptions and actual plan results.  These amounts are 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.  To the extent the other benefits are in an overfunded position, the Utility records a regulatory liability.(See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.)

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. 

In establishing health care cost assumptions, PG&E Corporation and the Utility consider recent cost trends and projections from industry experts.  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 2015 is 7.2%, gradually decreasing to the ultimate trend rate of 4% in 2024 and beyond.

Expected rates of return on plan assets were developed by estimating future 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 projected based on estimates of dividend yield and real earnings growth added to a long-term rate of inflation.  For the Utility’s defined benefit pension plan, the assumed return of 6.1% compares to a ten-year actual return of 7.8%.

The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 688 Aa-grade non-callable bonds at December 31, 2015.  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.

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

	Increase				Increase in Projected
	(Decrease) in		Increase in 2015 Pension		Benefit Obligation at
(in millions)	Assumption		Costs		December 31, 2015
Discount rate	(0.50)	%	$	119	$	1,227
Rate of return on plan assets	(0.50)	%		70		-
Rate of increase in compensation	0.50	%		59		285

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

	Increase		Increase in 2015		Increase in Accumulated
	(Decrease) in		Other Postretirement		Benefit Obligation at
(in millions)	Assumption		Benefit Costs		December 31, 2015
Health care cost trend rate	0.50	%	$	4	$	56
Discount rate	(0.50)	%		4		123
Rate of return on plan assets	(0.50)	%		10		-

NEW ACCOUNTING PRONOUNCEMENTS

See Note2 of the Notes to the Consolidated Financial Statements.

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that reflect management’s judgment and opinions and management's knowledge of facts as of the date of this report.  These forward-looking statements relate to, among other matters, estimated costs, including penalties and fines, associated with various investigations and proceedings; forecasts of pipeline-related expenses that the Utility will not recover through rates; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to regulatory assets and liabilities, environmental remediation, 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.  These forward-looking statements are subject to various risks and uncertainties, the realization or resolution of which may be outside of management’s control. Actual results could differ materially.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 outcomes of the 2015 GT&S rate case, the 2017 GRC, the TO rate cases, and other ratemaking and regulatory proceedings;

· the timing and outcomes of the federal criminal prosecution of the Utility, the pending CPUC investigation of the Utility’s natural gas distribution record-keeping practices, the SED’s unresolved enforcement matters relating to the Utility’s compliance with natural gas-related laws and regulations, and the other investigations that have been or may be commenced relating to the Utility’s compliance with natural gas-related laws and regulations, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with the outcomes;

· the timing and outcome of the CPUC’s investigation of communications between the Utility and the CPUC that may have violated the CPUC’s rules regarding ex parte communications or are otherwise alleged to be improper, whether additional criminal or regulatory investigations or enforcement actions are commenced with respect to allegedly improper communications, and whether such matters negatively affect the final decisions to be issued in the 2015 GT&S rate case or other ratemaking proceedings;

· whether PG&E Corporation and the Utility are able to repair the harm to their reputations caused by the criminal prosecution of the Utility, the state and federal investigations of natural gas incidents, matters relating to the indicted case, improper communications between the CPUC and the Utility; and the Utility’s ongoing work to remove encroachments from transmission pipeline rights-of-way;

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· whether the Utility can control its costs within the authorized levels of spending, the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs, and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons;

· the amount and timing of additional common stock and debt issuances by PG&E Corporation, including the dilutive impact of common stock issuances to fund PG&E Corporation’s equity contributions to the Utility as the Utility incurs charges and costs, including fines, that it cannot recover through rates;

· the outcome of the CPUC’s investigation into the Utility’s safety culture, and future legislative or regulatory actions that may be taken to require the Utility to separate its electric and natural gas businesses, restructure into separate entities, undertake some other corporate restructuring, or implement corporate governance changes;

· the outcomes of future investigations or other enforcement proceedings that may be commenced relating to the Utility’s compliance with laws, rules, regulations, or orders applicable to its operations, including the construction, expansion or replacement of its electric and gas facilities; inspection and maintenance practices, customer billing and privacy, and physical and cyber security;

· 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; and the extent to which the Utility is able to recover environmental costs in rates or from other sources;

· the ultimate amount of unrecoverable environmental costs the Utility incurs 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 nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, cooling water intake, or other issues; the impact of actions taken by state agencies,  including the California State Water Resources Board and the California State Lands Commission, that may affect the Utility’s ability to continue operating Diablo Canyon; and whether the Utility decides to resume its pursuit to renew the two Diablo Canyon NRC operating licenses, and if so, whether the licenses are renewed;

· the impact of droughts or other weather-related conditions or events, wildfires (such as the Butte fire), climate change, natural disasters, acts of terrorism, war, or vandalism (including cyber-attacks), and other events, 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; whether the Utility incurs liability to third parties for property damage or personal injury caused by such events; and whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events;

· how the CPUC and the CARB implement state environmental laws relating to GHG, renewable energy targets, energy efficiency standards, distributed energy resources, electric vehicles, and similar matters, including whether the Utility is able to continue recovering associated compliance costs, such as the cost of emission allowances and offsets under cap-and-trade regulations, and whether the Utility is able to timely recover its associated investment costs;

· whether the Utility’s climate change adaptation strategies are successful;

· the impact that reductions in customer demand for electricity and natural gas have on the Utility’s ability to make and recover its investments through rates and earn its authorized return on equity, and whether the Utility’s business strategy to address the impact of growing distributed and renewable generation resources and changing customer demand for natural gas and electric services is successful;

· the supply and price of electricity, natural gas, and nuclear fuel; 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 electric generation and energy commodity costs through rates, including its renewable energy procurement costs;

· whether the Utility’s information technology, operating systems and networks, including the advanced metering system infrastructure, customer billing, financial, records management, 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 against unauthorized or inadvertent disclosure of information contained in such systems and networks, including confidential proprietary information and the personal information of customers; and whether the Utility can continue to rely on third-party vendors and contractors that maintain and support some of the Utility’s information technology and operating systems;

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· the amount and timing of charges reflecting probable liabilities for third-party claims; the extent to which costs incurred in connection with third-party claims or litigation can be recovered through insurance, rates, or from other third parties; and whether the Utility can continue to obtain adequate insurance coverage for future losses or claims, especially following a major event that causes widespread third-party losses;

· 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;

· changes in credit ratings which could result in increased borrowing costs especially if PG&E Corporation or the Utility were to lose its investment grade credit ratings;

· 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 ultimate outcomes of the CPUC’s pending investigations, the criminal prosecution, and other enforcement matters affect the Utility’s ability to make distributions to PG&E Corporation, 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, regulations, or their interpretation; and

· the impact of changes in GAAP, 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 the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows, see Item. 1A. Risk Factors above and our detailed discussion of these matters contained elsewhere in MD&A.  PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to Item 7A is set forth under the heading “Risk Management Activities,” in MD&A in Item 7 and in Note 9: Derivatives and Note 10: Fair Value Measurements of the Notes to the Consolidated Financial Statements in Item 8.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E Corporation

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

	Year ended December 31,
	2015		2014		2013
Operating Revenues
Electric	$	13,657	$	13,658	$	12,494
Natural gas		3,176		3,432		3,104
Total operating revenues		16,833		17,090		15,598
Operating Expenses
Cost of electricity		5,099		5,615		5,016
Cost of natural gas		663		954		968
Operating and maintenance		6,951		5,638		5,775
Depreciation, amortization, and decommissioning		2,612		2,433		2,077
Total operating expenses		15,325		14,640		13,836
Operating Income		1,508		2,450		1,762
Interest income		9		9		9
Interest expense		(773)		(734)		(715)
Other income, net		117		70		40
Income Before Income Taxes		861		1,795		1,096
Income tax (benefit) provision		(27)		345		268
Net Income		888		1,450		828
Preferred stock dividend requirement of subsidiary		14		14		14
Income Available for Common Shareholders	$	874	$	1,436	$	814
Weighted Average Common Shares Outstanding, Basic		484		468		444
Weighted Average Common Shares Outstanding, Diluted		487		470		445
Net Earnings Per Common Share, Basic	$	1.81	$	3.07	$	1.83
Net Earnings Per Common Share, Diluted	$	1.79	$	3.06	$	1.83
See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2015		2014		2013
Net Income	$	888	$	1,450	$	828
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0, $10, and $80, at respective dates)		(1)		(14)		113
Net change in investments
(net of taxes of $12, $17, and $26 at respective dates)		(17)		(25)		38
Total other comprehensive income (loss)		(18)		(39)		151
Comprehensive Income		870		1,411		979
Preferred stock dividend requirement of subsidiary		14		14		14
Comprehensive Income Attributable to Common Shareholders	$	856	$	1,397	$	965
See accompanying Notes to the Consolidated Financial Statements.

70

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	123	$	151
Restricted cash		234		298
Accounts receivable
Customers (net of allowance for doubtful accounts of $54 and $66
at respective dates)		1,106		960
Accrued unbilled revenue		855		776
Regulatory balancing accounts		1,760		2,266
Other		286		377
Regulatory assets		517		444
Inventories
Gas stored underground and fuel oil		126		172
Materials and supplies		313		304
Income taxes receivable		155		198
Other		347		443
Total current assets		5,822		6,389
Property, Plant, and Equipment
Electric		48,532		45,162
Gas		16,749		15,678
Construction work in progress		2,059		2,220
Other		2		2
Total property, plant, and equipment		67,342		63,062
Accumulated depreciation		(20,619)		(19,121)
Net property, plant, and equipment		46,723		43,941
Other Noncurrent Assets
Regulatory assets		7,029		6,322
Nuclear decommissioning trusts		2,470		2,421
Income taxes receivable		135		91
Other		1,160		963
Total other noncurrent assets		10,794		9,797
TOTAL ASSETS	$	63,339	$	60,127
See accompanying Notes to the Consolidated Financial Statements.

71

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2015		2014
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,019	$	633
Long-term debt, classified as current		160		-
Accounts payable
Trade creditors		1,414		1,244
Regulatory balancing accounts		715		1,090
Other		398		476
Disputed claims and customer refunds		454		434
Interest payable		206		197
Other		1,997		1,846
Total current liabilities		6,363		5,920
Noncurrent Liabilities
Long-term debt		16,030		15,050
Regulatory liabilities		6,321		6,290
Pension and other postretirement benefits		2,622		2,561
Asset retirement obligations		3,643		3,575
Deferred income taxes		9,206		8,513
Other		2,326		2,218
Total noncurrent liabilities		40,148		38,207
Commitments and Contingencies (Note 13)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares;
492,025,443 and 475,913,404 shares outstanding at respective dates		11,282		10,421
Reinvested earnings		5,301		5,316
Accumulated other comprehensive (loss) income		(7)		11
Total shareholders' equity		16,576		15,748
Noncontrolling Interest - Preferred Stock of Subsidiary		252		252
Total equity		16,828		16,000
TOTAL LIABILITIES AND EQUITY	$	63,339	$	60,127
See accompanying Notes to the Consolidated Financial Statements.

72

PG&E Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2015		2014		2013
Cash Flows from Operating Activities
Net income	$	888	$	1,450	$	828
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		2,612		2,433		2,077
Allowance for equity funds used during construction		(107)		(100)		(101)
Deferred income taxes and tax credits, net		693		690		1,075
Disallowed capital expenditures		407		116		196
Other		326		286		355
Effect of changes in operating assets and liabilities:
Accounts receivable		(177)		13		(152)
Inventories		37		(22)		(10)
Accounts payable		(55)		(61)		113
Income taxes receivable/payable		43		376		(363)
Other current assets and liabilities		(315)		205		(469)
Regulatory assets, liabilities, and balancing accounts, net		(244)		(1,642)		(202)
Other noncurrent assets and liabilities		(355)		(67)		80
Net cash provided by operating activities		3,753		3,677		3,427
Cash Flows from Investing Activities
Capital expenditures		(5,173)		(4,833)		(5,207)
Decrease in restricted cash		64		3		29
Proceeds from sales and maturities of nuclear decommissioning
trust investments		1,268		1,336		1,619
Purchases of nuclear decommissioning trust investments		(1,392)		(1,334)		(1,604)
Other		22		114		56
Net cash used in investing activities		(5,211)		(4,714)		(5,107)
Cash Flows from Financing Activities
Borrowings (repayments) under revolving credit facilities		-		(260)		140
Net issuances (repayments) of commercial paper, net of discount
of $3, $2, and $2 at respective dates		683		(583)		542
Proceeds from issuance of short-term debt, net of issuance costs		-		300		-
Short-term debt matured		(300)		-		-
Proceeds from issuance of long-term debt, net of premium, discount,
and issuance costs of $27, $17 and $18 at respective dates		1,123		2,308		1,532
Repayments of long-term debt		-		(889)		(861)
Common stock issued		780		802		1,045
Common stock dividends paid		(856)		(828)		(782)
Other		-		42		(41)
Net cash provided by financing activities		1,430		892		1,575
Net change in cash and cash equivalents		(28)		(145)		(105)
Cash and cash equivalents at January 1		151		296		401
Cash and cash equivalents at December 31	$	123	$	151	$	296

73

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(684)	$	(633)	$	(623)
Income taxes, net		77		501		(41)
Supplemental disclosures of noncash investing and financing
activities
Common stock dividends declared but not yet paid	$	224	$	217	$	208
Capital expenditures financed through accounts payable		440		339		322
Noncash common stock issuances		21		21		22
Terminated capital leases		-		71		-
See accompanying Notes to the Consolidated Financial Statements.

74

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, 2012	430,718,293	$	8,428	$	4,747	$	(101)	$	13,074	$	252	$	13,326
Net income	-		-		828		-		828		-		828
Other comprehensive income	-		-		-		151		151		-		151
Common stock issued, net	25,952,131		1,067		-		-		1,067		-		1,067
Stock-based compensation amortization	-		56		-		-		56		-		56
Common stock dividends declared	-		-		(819)		-		(819)		-		(819)
Tax expense from employee stock plans	-		(1)		-		-		(1)		-		(1)
Preferred stock dividend requirement of
subsidiary	-		-		(14)		-		(14)		-		(14)
Balance at December 31, 2013	456,670,424	$	9,550	$	4,742	$	50	$	14,342	$	252	$	14,594
Net income	-		-		1,450		-		1,450		-		1,450
Other comprehensive loss	-		-		-		(39)		(39)		-		(39)
Common stock issued, net	19,242,980		823		-		-		823		-		823
Stock-based compensation amortization	-		65		-		-		65		-		65
Common stock dividends declared	-		-		(862)		-		(862)		-		(862)
Tax expense from employee stock plans	-		(17)		-		-		(17)		-		(17)
Preferred stock dividend requirement of
subsidiary	-		-		(14)		-		(14)		-		(14)
Balance at December 31, 2014	475,913,404	$	10,421	$	5,316	$	11	$	15,748	$	252	$	16,000
Net income	-		-		888		-		888		-		888
Other comprehensive loss	-		-		-		(18)		(18)		-		(18)
Common stock issued, net	16,112,039		801		-		-		801		-		801
Stock-based compensation amortization	-		66		-		-		66		-		66
Common stock dividends declared	-		-		(889)		-		(889)		-		(889)
Tax expense from employee stock plans	-		(6)		-		-		(6)		-		(6)
Preferred stock dividend requirement of
subsidiary	-		-		(14)		-		(14)		-		(14)
Balance at December 31, 2015	492,025,443	$	11,282	$	5,301	$	(7)	$	16,576	$	252	$	16,828
See accompanying Notes to the Consolidated Financial Statements.

75

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

	Year ended December 31,
	2015		2014		2013
Operating Revenues
Electric	$	13,657	$	13,656	$	12,489
Natural gas		3,176		3,432		3,104
Total operating revenues		16,833		17,088		15,593
Operating Expenses
Cost of electricity		5,099		5,615		5,016
Cost of natural gas		663		954		968
Operating and maintenance		6,949		5,635		5,742
Depreciation, amortization, and decommissioning		2,611		2,432		2,077
Total operating expenses		15,322		14,636		13,803
Operating Income		1,511		2,452		1,790
Interest income		8		8		8
Interest expense		(763)		(720)		(690)
Other income, net		87		77		84
Income Before Income Taxes		843		1,817		1,192
Income tax (benefit) provision		(19)		384		326
Net Income		862		1,433		866
Preferred stock dividend requirement		14		14		14
Income Available for Common Stock	$	848	$	1,419	$	852
See accompanying Notes to the Consolidated Financial Statements.

76

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2015		2014		2013
Net Income	$	862	$	1,433	$	866
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $1, $6, and $75, at respective dates)		(2)		(8)		106
Total other comprehensive income (loss)		(2)		(8)		106
Comprehensive Income	$	860	$	1,425	$	972
See accompanying Notes to the Consolidated Financial Statements.

77

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	59	$	55
Restricted cash		234		298
Accounts receivable
Customers (net of allowance for doubtful accounts of $54 and $66
at respective dates)		1,106		960
Accrued unbilled revenue		855		776
Regulatory balancing accounts		1,760		2,266
Other		284		375
Regulatory assets		517		444
Inventories
Gas stored underground and fuel oil		126		172
Materials and supplies		313		304
Income taxes receivable		130		168
Other		346		409
Total current assets		5,730		6,227
Property, Plant, and Equipment
Electric		48,532		45,162
Gas		16,749		15,678
Construction work in progress		2,059		2,220
Total property, plant, and equipment		67,340		63,060
Accumulated depreciation		(20,617)		(19,120)
Net property, plant, and equipment		46,723		43,940
Other Noncurrent Assets
Regulatory assets		7,029		6,322
Nuclear decommissioning trusts		2,470		2,421
Income taxes receivable		135		91
Other		1,053		864
Total other noncurrent assets		10,687		9,698
TOTAL ASSETS	$	63,140	$	59,865
See accompanying Notes to the Consolidated Financial Statements.

78

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2015		2014
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	1,019	$	633
Long-term debt, classified as current		160		-
Accounts payable
Trade creditors		1,414		1,243
Regulatory balancing accounts		715		1,090
Other		418		444
Disputed claims and customer refunds		454		434
Interest payable		203		195
Other		1,750		1,604
Total current liabilities		6,133		5,643
Noncurrent Liabilities
Long-term debt		15,680		14,700
Regulatory liabilities		6,321		6,290
Pension and other postretirement benefits		2,534		2,477
Asset retirement obligations		3,643		3,575
Deferred income taxes		9,487		8,773
Other		2,282		2,178
Total noncurrent liabilities		39,947		37,993
Commitments and Contingencies (Note 13)
Shareholders' Equity
Preferred stock		258		258
Common stock, $5 par value, authorized 800,000,000 shares;
264,374,809 shares outstanding at respective dates		1,322		1,322
Additional paid-in capital		7,215		6,514
Reinvested earnings		8,262		8,130
Accumulated other comprehensive income		3		5
Total shareholders' equity		17,060		16,229
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	63,140	$	59,865
See accompanying Notes to the Consolidated Financial Statements.

79

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2015		2014		2013
Cash Flows from Operating Activities
Net income	$	862	$	1,433	$	866
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		2,611		2,432		2,077
Allowance for equity funds used during construction		(107)		(100)		(101)
Deferred income taxes and tax credits, net		714		731		1,103
Disallowed capital expenditures		407		116		196
Other		263		226		299
Effect of changes in operating assets and liabilities:
Accounts receivable		(177)		16		(152)
Inventories		37		(22)		(10)
Accounts payable		(2)		(55)		99
Income taxes receivable/payable		38		395		(377)
Other current assets and liabilities		(342)		155		(404)
Regulatory assets, liabilities, and balancing accounts, net		(244)		(1,642)		(202)
Other noncurrent assets and liabilities		(340)		(66)		22
Net cash provided by operating activities		3,720		3,619		3,416
Cash Flows from Investing Activities
Capital expenditures		(5,173)		(4,833)		(5,207)
Decrease in restricted cash		64		3		29
Proceeds from sales and maturities of nuclear decommissioning
trust investments		1,268		1,336		1,619
Purchases of nuclear decommissioning trust investments		(1,392)		(1,334)		(1,604)
Other		22		29		21
Net cash used in investing activities		(5,211)		(4,799)		(5,142)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount
of $3, $2, and $2 at respective dates		683		(583)		542
Proceeds from issuance of short-term debt, net of issuance costs		-		300		-
Short-term debt matured		(300)		-		-
Proceeds from issuance of long-term debt, net of premium,
discount, and issuance costs of $27, $14, and $18 at respective dates		1,123		1,961		1,532
Long-term debt matured or repurchased		-		(539)		(861)
Preferred stock dividends paid		(14)		(14)		(14)
Common stock dividends paid		(716)		(716)		(716)
Equity contribution from PG&E Corporation		705		705		1,140
Other		14		56		(26)
Net cash provided by financing activities		1,495		1,170		1,597
Net change in cash and cash equivalents		4		(10)		(129)
Cash and cash equivalents at January 1		55		65		194
Cash and cash equivalents at December 31	$	59	$	55	$	65

80

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(675)	$	(618)	$	(600)
Income taxes, net		77		500		(62)
Supplemental disclosures of noncash investing and financing
activities
Capital expenditures financed through accounts payable	$	440	$	339	$	322
Terminated capital leases		-		71		-
See accompanying Notes to the Consolidated Financial Statements.

81

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, 2012	$	258	$	1,322	$	4,682	$	7,291	$	(93)	$	13,460
Net income		-		-		-		866		-		866
Other comprehensive income		-		-		-		-		106		106
Equity contribution		-		-		1,140		-		-		1,140
Tax expense from employee stock plans		-		-		(1)		-		-		(1)
Common stock dividend		-		-		-		(716)		-		(716)
Preferred stock dividend		-		-		-		(14)		-		(14)
Balance at December 31, 2013	$	258	$	1,322	$	5,821	$	7,427	$	13	$	14,841
Net income		-		-		-		1,433		-		1,433
Other comprehensive loss		-		-		-		-		(8)		(8)
Equity contribution		-		-		705		-		-		705
Tax expense from employee stock plans		-		-		(12)		-		-		(12)
Common stock dividend		-		-		-		(716)		-		(716)
Preferred stock dividend		-		-		-		(14)		-		(14)
Balance at December 31, 2014	$	258	$	1,322	$	6,514	$	8,130	$	5	$	16,229
Net income		-		-		-		862		-		862
Other comprehensive loss		-		-		-		-		(2)		(2)
Equity contribution		-		-		705		-		-		705
Tax expense from employee stock plans		-		-		(4)		-		-		(4)
Common stock dividend		-		-		-		(716)		-		(716)
Preferred stock dividend		-		-		-		(14)		-		(14)
Balance at December 31, 2015	$	258	$	1,322	$	7,215	$	8,262	$	3	$	17,060
See accompanying Notes to the Consolidated Financial Statements.

82

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, 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 CPUC and the FERC.  In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. 

This is a combined annual report of 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 in consolidation.The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility.  PG&E Corporation and the Utilityassessfinancial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).

The accompanying consolidated financial statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K.  The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, environmental remediation liabilities, AROs, 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.

83

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Regulation and Regulated Operations

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service.  The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. 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.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.  In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income.  (See “Revenue Recognition” below.)

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.  To the extent that portions of the Utility’s operations cease to be subject to costofservice 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.

Revenue Recognition

The Utility recognizes revenues when electricity and natural gas services are delivered.The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets.Rates charged to customers are based on CPUC and FERC authorized revenue requirements.

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, 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 that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.Generally, revenue is recognized ratably over the year.

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.In general, 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 periodic (often annual) TO 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.

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. 

84

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.  (See “Resolution of Remaining Chapter 11 Disputed Claims” in Note 13below.) 

Allowance for Doubtful Accounts Receivable

PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer accounts receivable at estimated net realizable value.  The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.

Inventories

Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.

Emission Allowances

The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.

Property, Plant, and Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  (See “AFUDC” below.)  The Utility’s total 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)	2015		2014
Electricity generating facilities (1)	5 to 100	$	9,860	$	9,374
Electricity distribution facilities	15 to 55		28,476		26,633
Electricity transmission facilities	15 to 75		10,196		9,155
Natural gas distribution facilities	5 to 60		10,397		9,741
Natural gas transportation and storage facilities	5 to 65		6,352		5,937
Construction work in progress			2,059		2,220
Total property, plant, and equipment			67,340		63,060
Accumulated depreciation			(20,617)		(19,120)
Net property, plant, and equipment		$	46,723	$	43,940

(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 13 below.)

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 balance 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 3.80% in 2015, 3.77% in 2014, and 3.51% in 2013.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.

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AFUDC

AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service 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 related to debt and equity, respectively, of $48million and $107million during2015, $45 million and $100 million during2014, and $47 million and $101 million during 2013.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2015 and 2014, including nuclear decommissioning obligations:

(in millions)		2015		2014
ARO liability at beginning of year	$	3,575	$	3,538
Revision in estimated cash flows		13		(16)
Accretion		169		163
Liabilities settled		(114)		(110)
ARO liability at end of year	$	3,643	$	3,575

The Utility has not recorded a liability related to certain ARO’s for assets that are expected to operate in perpetuity.  As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, photovoltaic facilities, and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration or land to the conditions under certain agreements.

Nuclear Decommissioning Obligation

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.

The Utility adjusts its nuclear decommissioning obligation to reflect changes in the estimated costs of decommissioning its nuclear power facilities and records this as an adjustment to the ARO liability on its Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued was $2.5 billion at December 31, 2015and 2014.The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $3.5 billion at December 31, 2015 and2014 (or $6.1 billion in future dollars). These estimates are based on the 2012 decommissioning cost studies, prepared in accordance with CPUC requirements.

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Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge 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.  The Utility recorded charges of $407 million in 2015 for estimated capital spending that is probable of disallowance related to the Penalty Decision and $116 million and $196 million in 2014 and 2013, respectively, for PSEP capital costs that are expected to exceed the CPUC’s authorized levels or that are specifically disallowed.  (See “Enforcement and Litigation Matters” in Note 13 below).

Nuclear Decommissioning Trusts

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one 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 by the trust is determined by specific identification.

Variable Interest Entities

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 that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate 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.  To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2015,it assessed 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, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with anyof the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2015, it did not consolidate any of them.

Other Accounting Policies

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For other accounting policies impacting PG&E Corporation’s and the Utility’s consolidated financial statements, see “Income Taxes” in Note 8, “Derivatives” in Note 9, “Fair Value Measurements” in Note 10, and “Contingencies and Commitments” in Note 13 of the Notes to the Consolidated Financial Statements.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2015 consisted of the following:

	Pension		Other		Other
(in millions, net of income tax)	Benefits		Benefits		Investments		Total
Beginning balance	$	(21)	$	15	$	17	$	11
Other comprehensive income before reclassifications:
Unrecognized net actuarial loss
(net of taxes of $51, $21, and $0, respectively)		(76)		(31)		-		(107)
Regulatory account transfer
(net of taxes of $51, $21, and $0, respectively)		73		31		-		104
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $7, $8, and $0, respectively) (1)		8		11		-		19
Amortization of net actuarial loss
(net of taxes of $4, $1, and $0, respectively) (1)		6		3		-		9
Regulatory account transfer
(net of taxes of $10, $9, and $0, respectively) (1)		(13)		(13)		-		(26)
Realized gain on investments
(net of taxes of $0, $0, and $12, respectively)		-		-		(17)		(17)
Net current period other comprehensive loss		(2)		1		(17)		(18)
Ending balance	$	(23)	$	16	$	-	$	(7)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)

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The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2014 consisted of the following:

	Pension		Other		Other
(in millions, net of income tax)	Benefits		Benefits		Investments		Total
Beginning balance	$	(7)	$	15	$	42	$	50
Other comprehensive income before reclassifications:
Change in investments
(net of taxes of $0, $0, and $4, respectively)		-		-		5		5
Unrecognized net actuarial loss
(net of taxes of $404, $19, and $0, respectively)		(588)		(28)		-		(616)
Unrecognized prior service cost
(net of taxes of $0, $0, and $0, respectively)		1		-		-		1
Regulatory account transfer
(net of taxes of $394, $19, and $0, respectively)		573		28		-		601
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $8, $9, and $0, respectively) (1)		12		14		-		26
Amortization of net actuarial loss
(net of taxes of $1, $1, and $0, respectively) (1)		1		1		-		2
Regulatory account transfer
(net of taxes of $9, $10, and $0, respectively) (1)		(13)		(15)		-		(28)
Realized gain on investments
(net of taxes of $0, $0, and $20, respectively)		-		-		(30)		(30)
Net current period other comprehensive loss		(14)		-		(25)		(39)
Ending balance	$	(21)	$	15	$	17	$	11

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)

With the exception of other investments, there was no material difference between PG&E Corporation and the Utility for the information disclosed above.

New Accounting Pronouncements

Recognition and Measurement of Financial Assets and Financial Liabilities

InJanuary 2016, the FASB issued ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which amends guidance to help improve the recognition and measurement of financial instruments. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018.PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes, which amends existing guidance on the presentation of deferred income tax assets and liabilities. The amendments in the ASU require that all deferred tax liabilities and assets be classified as noncurrent on the balance sheet.  This ASU will be effective for PG&E Corporation and the Utilityon January 1, 2017, with earlier adoption permitted.  PG&E Corporation and the Utility have implemented this standard as of the year ended December 31, 2015 on a prospective basis and the prior periods have not been retrospectively adjusted. 

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Fair Value Measurement

In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which removes the requirement to categorize within the fair value hierarchy all investments measured using net asset value per share as a practical expedient.  The ASU became effective for PG&E Corporation and the Utility on January 1, 2016. This standard will be adopted for related disclosures in the first quarter of 2016 and will not have an impact on the consolidated financial statements. 

Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued ASU No. 2015-05,Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement, which adds guidance to help entities evaluate the accounting treatment for cloud computing arrangements.  The ASUbecame effective for PG&E Corporation and the Utilityon January 1, 2016.  PG&E Corporation and the Utility have determined that this ASU will not impact their consolidated financial statements and related disclosures and will adopt this standard starting in the first quarter of2016.

Presentation of Debt Issuance Costs

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which amends existing presentation of debt issuance costs.  PG&E Corporation and the Utility currently disclose debt issuance costs in current assets – other and noncurrent assets – other.The amendments in this ASU, that became effective for PG&E Corporation and the Utility on January 1, 2016, require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.  PG&E Corporation and the Utility will adopt this standard in the first quarter of 2016 and do not expect the reclassification to have a material impact on their consolidated financial statements. 

Revenue Recognition Standard

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, deferring the effective date of this amendment for PG&E Corporation and the Utility by one year to January 1, 2018, with early adoption permitted as of the original effective date of January 1, 2017.PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures.

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NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance at December 31,				Recovery
(in millions)	2015		2014		Period
Pension benefits (1)	$	2,414	$	2,347	Indefinitely (4)
Deferred income taxes (1)		3,054		2,390	47 years
Utility retained generation (2)		411		456	10 years
Environmental compliance costs (1)		748		717	32 years
Price risk management (1)		138		127	10 years
Electromechanical meters (3)		-		70	-
Unamortized loss, net of gain, on reacquired debt (1)		94		113	11 years
Other		170		102	Various
Total long-term regulatory assets	$	7,029	$	6,322

(1) Represents the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP.

(2) 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, 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. 

(3) Represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices. As of December 31, 2015, the remaining balance of $70 million is included in current regulatory assets on the Consolidated Balance Sheets.

(4) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.

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, 2015 and 2014, the Utility had current regulatory liabilities of $676 million and $261 million, respectively. At December 31, 2015, the current regulatory liabilities consisted primarily of a $400 million bill credit to the Utility’s natural gas customers resulting from the Penalty Decision. (See Note 13 below.) Current regulatory liabilities are included within current liabilities-other in the Consolidated Balance Sheets.

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Long -Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2015		2014
Cost of removal obligations (1)	$	4,605	$	4,211
Recoveries in excess of AROs (2)		631		754
Public purpose programs (3)		600		701
Other		485		624
Total long-term regulatory liabilities	$	6,321	$	6,290

(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.

(2) Represents the cumulative differences between ARO expenses and amounts collected in rates.  Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments.  (See Note 10 below.)

(3) 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.

Regulatory Balancing Accounts

The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings.  To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable.Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets.  These differences do not have an impact on net income.  Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected. 

Current regulatory balancing accounts receivable and payable are comprised of the following:

	Receivable
	Balance at December 31,
(in millions)	2015		2014
Electric distribution	$	380	$	344
Utility generation		122		261
Gas distribution		493		566
Energy procurement		262		608
Public purpose programs		155		109
Other		348		378
Total regulatory balancing accounts receivable	$	1,760	$	2,266

	Payable
	Balance at December 31,
(in millions)	2015		2014
Energy procurement	$	112	$	188
Public purpose programs		244		154
Other		359		748
Total regulatory balancing accounts payable	$	715	$	1,090

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The electric distribution, utility generation, and gas distribution balancing accounts track the collection of revenue requirements approved in the GRC.  Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities.  Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency and low income energy efficiency.

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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)	2015		2014
PG&E Corporation
Senior notes, 2.40%, due 2019		350		350
Total PG&E Corporation long-term debt		350		350
Utility
Senior notes:
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		400
3.25% due 2023		375		375
3.85% due 2023		300		300
3.40% due 2024		350		350
3.75% due 2024		450		450
3.50% due 2025		600		-
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		400
3.75% due 2042		350		350
4.60% due 2043		375		375
5.125% due 2043		500		500
4.75% due 2044		675		675
4.30% due 2045		600		500
4.25% due 2046		450		-
Unamortized discount, net of premium		(53)		(43)
Total senior notes, net of current portion		14,572		13,432
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 (1), due 2016 and 2026 (4)		309		309
Less: current portion		(160)		-
Total pollution control bonds		1,108		1,268
Total Utility long-term debt, net of current portion		15,680		14,700
Total consolidated long-term debt, net of current portion	$	16,030	$	15,050

(1) At December 31, 2015, interest rates on these bonds were 0.01%.

(2) Each series of these bonds is supported by a separate letter of credit.  In December 2015, the letters of credit were extended to December 1, 2020. 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) Each series of these bonds is supported by a separate direct-pay letter of credit. Series C and D letters of credit expire on December 3, 2016 to coincide with the maturity of the underlying bonds.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.

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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.  Substantially all of the net proceeds 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.  In 1999, the Utility sold all bond-financed facilities at the non-retired units of 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 for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are outstanding.  Except for components that may have been abandoned in place or disposed of as scrap or that are permanently non-operational, the Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities.

Short-term Borrowings

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities andcommercial paper programs at December 31, 2015:

		Credit			Letters of		Commercial
	Termination	Facility			Credit		Paper		Facility
(in millions)	Date	Limit			Outstanding		Outstanding		Availability
PG&E Corporation	April 2020	$	300	(1)	$	-	$	-	$	300
Utility	April 2020		3,000	(2)		33		1,019		1,948
Total revolving credit facilities		$	3,300		$	33	$	1,019	$	2,248

(1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

(2) Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans.

For the year ended December 31,2015, PG&E Corporation’s average outstanding commercial paper balance was $64million and the maximum outstanding balance during the year was $128 million.  For 2015, the Utility’s average outstanding commercial paper balance was $678million and the maximum outstanding balance during the year was $1.5 billion.  There were no bank borrowings for both PG&E Corporation and the Utility in 2015. 

Revolving Credit Facilities

On April 27, 2015, PG&E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities.The amendments and restatements extended the termination dates of the credit facilities from April 1, 2019 to April 27, 2020, reduced the amount of lender commitments to the letter of credit sublimits from $100 million to $50 million for PG&E Corporation’s credit facility and from $1.0 billion to $500 million for the Utility’s credit facility, and reduced the swingline commitment on the Utility’s credit facility from $300 million to $75 million.  PG&E Corporation's and the Utility's revolving credit facilities may be used for working capital, the repayment of commercial paper, and other corporate purposes.  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.

Borrowings under each amended and restated credit agreement (other than swing line loans) will bear interest based, at each borrower’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 overnight federal funds rate, and the one-month LIBOR plus an applicable margin.  The applicable margin for LIBOR loans will range between 0.9% and 1.475% under PG&E Corporation’s amended and restated credit agreement and between 0.8% and 1.275% under the Utility’s amended and restated credit agreement. The applicable margin for base rate loans will range between 0% and 0.475% under PG&E Corporation’s amended and restated credit agreement and between 0% and 0.275% under the Utility’s amended and restated credit agreement.  In addition, the facility fee under PG&E Corporation’s and the Utility’s amended and restated credit agreements will range between 0.1% and 0.275% and between 0.075% and 0.225%, respectively.

PG&E Corporation’s and the Utility’s revolving credit facilities include usual and customary provisions for revolving credit facilities of this type, including those regarding events of default and covenants limiting liens to those permitted under their senior note indentures, mergers, sales of all or substantially all of their assets, and other fundamental changes.  In addition, the respective 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 outstanding common stock and at least 70% of the outstanding voting capital stock of the Utility. 

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Commercial Paper Programs

The borrowings from PG&E Corporation and the Utility’s commercial paper programs are used primarily to fund temporary financing needs.  On July 2, 2015, the Utility increased the commercial paper program limit from $1.75 billion to $2.5 billion. PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and $2.5 billion, respectively. PG&E Corporation and the Utility treat the amount of outstanding commercial paper as a reduction to the amount available under their respective revolving credit facilities.  The commercial paper may have maturities up to 365 days and ranks equally with PG&E Corporation’s and 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.  For 2015, the average yield on outstanding PG&E Corporation and Utility commercial paper was 0.38% and 0.42%, respectively.

Other Short-term Borrowings

On May 11, 2015, $300 million principal amount of the Utility’s Floating Rate Senior Notes matured.

Repayment Schedule

PG&E Corporation’s and the Utility’s combined long-termdebt principal repayment amounts at December 31, 2015are reflected in the table below:

(in millions,
except interest rates)	2016			2017				2018				2019				2020			Thereafter				Total
PG&E Corporation
Average fixed interest rate		-				-				-				2.40	%		-				-				2.40	%
Fixed rate obligations	$	-			$	-			$	-			$	350		$	-			$	-			$	350
Utility
Average fixed interest rate		-				5.63	%			8.25	%			-			3.50	%			4.91	%			5.05	%
Fixed rate obligations	$	-			$	700			$	800			$	-		$	800			$	12,670			$	14,970
Variable interest rate
as of December 31, 2015		0.01	%			-				-				0.01	%		0.01	%			-				0.01	%
Variable rate obligations (1)	$	160			$	-			$	-			$	149		$	614			$	-			$	923
Total consolidated debt	$	160			$	700			$	800			$	499		$	1,414			$	12,670			$	16,243

(1)These bonds, due in 2016 and 2026, are backed by separate letters of credit that expire on December 3, 2016, June 5, 2019, or December 1, 2020.

NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 492,025,443shares of common stock outstanding at December 31, 2015.  PG&E Corporation held all of the Utility’s outstanding common stock at December 31,2015.

In February 2015, PG&E Corporation entered into a new equity distribution agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $500 million.  During 2015, PG&E Corporation sold   1.4 million shares under this agreement for cash proceeds of $74 million, net of commissions paid of $1 million.

In August 2015, PG&E Corporation sold 6.8 million shares of its common stock in an underwritten public offeringfor cash proceeds of $352 million, net of fees.

In addition, during 2015, PG&E Corporation sold 7.9 million shares of common stock under its 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans for total cash proceeds of $354million.

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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.  For 2015, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.455 per share.

Under their respective credit agreements, PG&E Corporation and the Utility are each required to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%. In addition, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on a weighted average over four years. PG&E Corporation and the Utility are in compliance with these restrictions. At December 31, 2015, the Utility had restricted net assets of $15.2 billion and was limited to $110 million of additional common stock dividends it could pay to PG&E Corporation.

Long-Term Incentive Plan

The PG&E Corporation LTIPpermits various forms of share-based incentive awards, including restricted stock awards, restricted stock units, performance shares, 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 certain share-based awards. In May 2014, the 2006 LTIP was terminated and the 2014 LTIP became effective.  A maximum of 17 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the 2014 LTIP, of which 15,674,803 shares were available for future awards at December 31, 2015.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2015, 2014, and 2013:

(in millions)	2015		2014		2013
Restricted stock units	$	47	$	42	$	36
Performance shares		46		36		28
Total compensation expense (pre-tax)	$	93	$	78	$	64
Total compensation expense (after-tax)	$	55	$	47	$	38

The amount of share-based compensation costs capitalized during 2015, 2014, and 2013 was immaterial.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Restricted Stock Units

Prior to 2014, restricted stock units generally vested over four years 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. Restricted stock units granted in 2014 and 2015 generally vest equally over three years.Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units.  Compensation expense is generally recognized rateably over the vesting period based on grant-date fair value.  The weighted average grant-date fair value forrestricted stock units granted during 2015, 2014, and 2013 was $53.30, $43.76, and $42.92, respectively.  The total fair value of restricted stock units that vested during 2015, 2014, and 2013 was $57 million, $34 million, and $30 million, respectively.  The tax benefit from restricted stock units that vested during each period was not material.  As of December 31, 2015, $45million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.48years.

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The following table summarizes restricted stock unit activity for 2015:

	Number of	Weighted Average Grant-
	Restricted Stock Units	Date Fair Value
Nonvested at January 1	2,538,357	$	43.39
Granted	820,834		53.30
Vested	(1,304,150)		43.51
Forfeited	(82,142)		45.63
Nonvested at December 31	1,972,899	$	47.33

Performance Shares

Performance shares generally will vest threeyears after the grant date. Upon vesting, performance shares are settled in shares of common stock based on PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period.  Dividend equivalentsare paid in cash based on the amount of common stock to which the recipients are entitled. 

Compensation expense attributable to performance share is generally recognized rateably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model.The weighted average grant-date fair value for performance shares granted during 2015,2014, and 2013 was $68.27, $51.81, and $33.45 respectively.  There was no tax benefit associated with performance shares during each of these periods.  As of December 31, 2015, $36 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of1.45 years.

The following table summarizes activity for performance shares in2015:

	Number of	Weighted Average Grant-
	Performance Shares	Date Fair Value
Nonvested at January 1	1,693,939	$	42.37
Granted	669,519		68.27
Vested	(421,262)		33.57
Forfeited (1)	(491,584)		35.56
Nonvested at December 31	1,450,612	$	59.24
(1) Includes performance shares that expired with 50% value as a result of total shareholder return results.

NOTE 6: PREFERRED STOCK

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 anypreferred stock outstanding.

The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100par value preferred stock.  At December 31, 2015 and December 31, 2014, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36%and 5% that are redeemable between $25.75 and $27.25 per share.  The Utility’s preferred stock outstanding are not subject to mandatory redemption.  All outstanding preferred stock has a $25 par value.

At December 31, 2015, 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, 2015, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.

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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. The Utility paid $14 million of dividends on preferred stock in each of 2015, 2014, and 2013.

NOTE 7: EARNINGS PER SHARE

PG&E Corporation’s basic 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 2015, 2014, and 2013.

	Year Ended December 31,
(in millions, except per share amounts)	2015		2014		2013
Income available for common shareholders	$	874	$	1,436	$	814
Weighted average common shares outstanding, basic		484		468		444
Add incremental shares from assumed conversions:
Employee share-based compensation		3		2		1
Weighted average common share outstanding, diluted		487		470		445
Total earnings per common share, diluted	$	1.79	$	3.06	$	1.83

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 8: INCOME TAXES

PG&E Corporation and the Utility use the liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year.PG&E Corporation and the Utility estimate current period 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 those arising from depreciation expense.

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 in the financial statements represents an unrecognized tax benefit. 

Investment tax credits are deferred and amortized to income over time.  PG&E Corporation amortizes its investment tax credits over the projected investment recovery period.The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.

PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more.  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.

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The significant components of income tax provision (benefit)by taxing jurisdiction were as follows:

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2015		2014		2013		2015		2014		2013
Current:
Federal	$	(89)	$	(84)	$	(218)	$	(88)	$	(84)	$	(222)
State		11		(41)		(26)		6		(29)		(23)
Deferred:
Federal		131		396		552		136		426		604
State		(76)		78		(35)		(69)		75		(28)
Tax credits		(4)		(4)		(5)		(4)		(4)		(5)
Income tax provision	$	(27)	$	345	$	268	$	(19)	$	384	$	326

The following table describes net deferred income tax liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2015		2014		2015		2014
Deferred income tax assets:
Customer advances for construction	$	69	$	88	$	69	$	88
Environmental reserve		85		111		85		111
Compensation and benefits		219		244		145		173
Tax carryforwards		1,703		1,177		1,462		946
Greenhouse gas allowances		340		56		340		56
Other		44		74		61		100
Total deferred income tax assets	$	2,460	$	1,750	$	2,162	$	1,474
Deferred income tax liabilities:
Regulatory balancing accounts	$	691	$	512	$	691	$	512
Property related basis differences		9,656		8,683		9,638		8,666
Income tax regulatory asset (1)		1,244		974		1,245		974
Other		75		88		75		86
Total deferred income tax liabilities	$	11,666	$	10,257	$	11,649	$	10,238
Total net deferred income tax liabilities	$	9,206	$	8,507	$	9,487	$	8,764
Classification of net deferred income tax liabilities:
Included in current liabilities (assets)	$	-	$	(6)	$	-	$	(9)
Included in noncurrent liabilities		9,206		8,513		9,487		8,773
Total net deferred income tax liabilities	$	9,206	$	8,507	$	9,487	$	8,764

(1)Representsthe deferred income tax component of the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP.  (See Note 3 above.)

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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,
	2015		2014		2013		2015		2014		2013
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) (1)	(4.9)		1.4		(3.1)		(4.8)		1.6		(2.2)
Effect of regulatory treatment
of fixed asset differences (2)	(33.6)		(15.0)		(4.2)		(33.7)		(14.7)		(3.8)
Tax credits	(1.3)		(0.7)		(0.4)		(1.3)		(0.7)		(0.4)
Benefit of loss carryback	(1.5)		(0.8)		(1.1)		(1.5)		(0.8)		(1.0)
Non deductible penalties (3)	4.3		0.3		0.8		4.3		0.3		0.7
Other, net	(1.1)		(0.8)		(2.2)		(0.2)		0.4		(0.9)
Effective tax rate	(3.1)	%	19.4	%	24.8	%	(2.2)	%	21.1	%	27.4	%

(1)Includes the effect of state flow-through ratemaking treatment.  In 2015, amounts include an agreement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions.   

(2)Includes the effect of federal flow-through ratemaking treatment for certain property-related costsin 2015 and 2014 as authorized by the 2014 GRC decision.  Amounts are impacted by the level of income before income taxes. 

(3)Represents the effects of non-tax deductible fines and penalties associated with the Penalty Decision.  (For more information about the Penalty Decision see Note 13 below.) 

Unrecognized tax benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation						Utility
(in millions)	2015		2014		2013		2015		2014		2013
Balance at beginning of year	$	713	$	666	$	581	$	707	$	660	$	575
Additions for tax position taken
during a prior year		40		7		12		40		7		12
Reductions for tax position
taken during a prior year		(349)		(9)		(6)		(349)		(9)		(6)
Additions for tax position
taken during the current year		64		61		79		64		61		79
Settlements		-		(12)		-		-		(12)		-
Balance at end of year	$	468	$	713	$	666	$	462	$	707	$	660

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2015for PG&E Corporation and the Utility was $50 million.

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of several matters, including audits. As of December 31, 2015, it is reasonably possible that unrecognized tax benefits will decrease by approximately $60 million within the next 12 months.

Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income.  For the years ended December 31, 2015, 2014, and 2013, these amounts were immaterial.

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IRS settlements

PG&E Corporation participated in the Compliance Assurance Process in 2015, a real-time IRS audit intended to expedite resolution of tax matters.  The Compliance Assurance Process audit culminates with a letter from the IRS indicating its acceptance of the return.

PG&E Corporation’s tax returns have been accepted through 2014 except for a few matters, the most significant of which relates to deductible repair costs.  In December 2015, PG&E Corporation reached an agreement with the IRS on deductible repair costs for the 2011 tax year, subject to approval by the Joint Committee on Taxation.  Deductible repair costs will continue to be subject to examination by the IRS for subsequent years.  The IRS is expected to issue guidance in 2016 that clarifies which repair costs are deductible for the natural gas transmission and distribution businesses.  Tax years after 2004 remain subject to examination by the state of California.

Carryforwards

The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:

	December 31,		Expiration
(in millions)	2015		Year
Federal:
Net operating loss carryforward	$	4,856	2029 - 2035
Tax credit carryforward		110	2029 - 2035
Charitable contribution loss carryforward		178	2017 - 2020
State:
Net operating loss carryforward	$	80	2033 - 2034
Tax credit carryforward		59	Various
Charitable contribution loss carryforward		119	2019 - 2020

PG&E Corporation believes it is more likely than not the tax benefits associated with the federal and California net operating losses, charitable contributions and tax credits can be realized within the carryforward periods, therefore no valuation allowance was recognized as of December 31, 2015 for these tax attributes. As of December 31, 2015, PG&E Corporation had approximately $29million of federal net operating loss carryforwards related to the tax benefit on employee stock plans that would be recorded in additional paid-in capital when used.

NOTE 9: DERIVATIVES

Use of Derivative Instruments

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities.  Procurement costs are recovered through customer rates.  The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices.  Derivatives include forward contracts, swaps, futures, options, and CRRs.

Derivatives are presented in the Utility’s Consolidated Balance Sheets on a net basis in accordance with master netting arrangements for each counterparty.  The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.  

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets.  These instruments are not held for speculative purposes and are subject to certain regulatory requirements.  The Utility expects to fully recover in rates all costs related to derivatives as long as the current ratemaking mechanism remains in place and the Utility’s price risk management activities are carried out in accordance with CPUC directives.  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.  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.

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The Utility elects the normal purchase and sale exception for eligible derivatives.  Eligible derivatives are those 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.  These items are not reflected in the Consolidated Balance Sheets at fair value.  Eligible derivatives are accounted for under the accrual method of accounting.

Volume of Derivative Activity

At December 31, 2015 and 2014, respectively, the volumes of the Utility’s outstanding derivatives were as follows:

		Contract Volume
Underlying Product	Instruments	2015	2014
Natural Gas (1) (MMBtus (2))	Forwards and Swaps	333,091,813	308,130,101
	Options	111,550,004	164,418,002
Electricity (Megawatt-hours)	Forwards and Swaps	3,663,512	5,346,787
	Congestion Revenue Rights (3)	216,383,389	224,124,341

(1)Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.

(2) Million British Thermal Units.

(3)CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

At December 31, 2015, 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	$	97	$	(4)	$	25	$	118
Other noncurrent assets – other		172		(2)		-		170
Current liabilities – other		(102)		4		44		(54)
Noncurrent liabilities – other		(140)		2		21		(117)
Total commodity risk	$	27	$	-	$	90	$	117

At December 31, 2014, 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	$	73	$	(4)	$	19	$	88
Other noncurrent assets – other		178		(13)		-		165
Current liabilities – other		(78)		4		26		(48)
Noncurrent liabilities – other		(140)		13		9		(118)
Total commodity risk	$	33	$	-	$	54	$	87

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Gains and losses associated with price risk management activities were recorded as follows:

	Commodity Risk
	For the year ended December 31,
(in millions)	2015		2014		2013
Unrealized gain/(loss) - regulatory assets and liabilities (1)	$	(6)	$	124	$	238
Realized loss - cost of electricity (2)		(14)		(83)		(178)
Realized loss - cost of natural gas (2)		(10)		(8)		(22)
Total commodity risk	$	(30)	$	33	$	38

(1)Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, 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 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, 2015, 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)	2015		2014
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(2)	$	(47)
Related derivatives in an asset position		-		-
Collateral posting in the normal course of business related to
these derivatives		-		44
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(2)	$	(3)

(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 10: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, price risk management instruments, and other investments at fair value.  A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

• Level1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

• Level2 – Other inputs that are directly or indirectly observable in the marketplace.

• Level3 – 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 and other investments are held by PG&E Corporation and not the Utility):

	Fair Value Measurements
	At December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	64	$	-	$	-	$	-	$	64
Nuclear decommissioning trusts
Money market investments		36		-		-		-		36
Global equity securities		1,520		13		-		-		1,533
Fixed-income securities		694		521		-		-		1,215
Total nuclear decommissioning trusts (2)		2,250		534		-		-		2,784
Price risk management instruments
(Note 9)
Electricity		-		9		259		18		286
Gas		-		1		-		1		2
Total price risk management
instruments		-		10		259		19		288
Rabbi trusts
Fixed-income securities		-		57		-		-		57
Life insurance contracts		-		70		-		-		70
Total rabbi trusts		-		127		-		-		127
Long-term disability trust
Money market investments		7		-		-		-		7
Global equity securities		-		26		-		-		26
Fixed-income securities		-		132		-		-		132
Total long-term disability trust		7		158		-		-		165
Total assets	$	2,321	$	829	$	259	$	19	$	3,428
Liabilities:
Price risk management instruments
(Note 9)
Electricity	$	69	$	1	$	170	$	(70)	$	170
Gas		-		2		-		(1)		1
Total liabilities	$	69	$	3	$	170	$	(71)	$	171

(1)Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $314 million, primarily related to deferred taxes on appreciation of investment value.

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	Fair Value Measurements
	At December 31, 2014
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	94	$	-	$	-	$	-	$	94
Nuclear decommissioning trusts
Money market investments		17		-		-		-		17
Global equity securities		1,585		13		-		-		1,598
Fixed-income securities		741		389		-		-		1,130
Total nuclear decommissioning trusts (2)		2,343		402		-		-		2,745
Price risk management instruments
(Note 9)
Electricity		-		17		232		2		251
Gas		1		1		-		-		2
Total price risk management
instruments		1		18		232		2		253
Rabbi trusts
Fixed-income securities		-		42		-		-		42
Life insurance contracts		-		72		-		-		72
Total rabbi trusts		-		114		-		-		114
Long-term disability trust
Money market investments		7		-		-		-		7
Global equity securities		-		25		-		-		25
Fixed-income securities		-		128		-		-		128
Total long-term disability trust		7		153		-		-		160
Other investments		33		-		-		-		33
Total assets	$	2,478	$	687	$	232	$	2	$	3,399
Liabilities:
Price risk management instruments
(Note 9)
Electricity	$	47	$	5	$	163	$	(52)	$	163
Gas		-		3		-		-		3
Total liabilities	$	47	$	8	$	163	$	(52)	$	166

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $324 million, primarily related to deferred taxeson 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 tables above.  Investments, primarily consisting of equity securities, that are valued using a net asset value per share can be redeemed quarterly with notice not to exceed 90 days.  Equity investments valued at net asset value per share utilize investment strategies aimed at matching the performance of indexed funds.  Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the year ended December 31, 2015 and 2014.

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Trust Assets

Nuclear decommissioning trust assets and other trust assets are composed primarily of equity securities and debt securities.  In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.  Equity securities also include commingled funds that are composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world. Investments in these funds are classified as Level 2 because price quotes 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 using 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. 

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.  Exchange-traded options are valued using observable market data and market-corroborated data and 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.Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.

Level 3 Measurements and Sensitivity Analysis

The Utility’s market and credit risk management function, which reports to the Chief Risk and Audit Officer of the Utility, is responsible for determining the fair value of the Utility’s price risk management derivatives.  The Utility’s financeand risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative.  Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

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 9 above.)

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	Fair Value at
(in millions)	At December 31, 2015				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	259	$	63	Market approach	CRR auction prices	$	(161.36) - 8.76
Power purchase agreements	$	-	$	107	Discounted cash flow	Forward prices	$	15.08 - 37.27

1. Represents price per megawatt-hour

	Fair Value at
(in millions)	At December 31, 2014				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	232	$	63	Market approach	CRR auction prices	$	(15.97) - 8.17
Power purchase agreements	$	-	$	100	Discounted cash flow	Forward prices	$	16.04 - 56.21

(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, 2015and 2014, respectively:

	Price Risk Management Instruments
(in millions)	2015		2014
Asset (liability) balance as of January 1	$	69	$	(30)
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		20		99
Asset (liability) balance as of December 31	$	89	$	69

    (1) The costs related to 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, floating rate senior notes, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2015 and 2014,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 bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at December 31, 2015 and 2014.

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,
	2015				2014
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation	$	350	$	354	$	350	$	352
Utility		14,918		16,422		13,778		15,851

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Available for Sale Investments

The following table provides a summary of available-for-sale investments:

				Total		Total
	Amortized			Unrealized		Unrealized		Total Fair
(in millions)	Cost			Gains		Losses		Value
As of December 31, 2015
Nuclear decommissioning trusts
Money market investments	$	36	$	-	$	-	$	36
Global equity securities		508		1,034		(9)		1,533
Fixed-income securities		1,165		58		(8)		1,215
Total (1)	$	1,709	$	1,092	$	(17)	$	2,784
As of December 31, 2014
Nuclear decommissioning trusts
Money market investments	$	17	$	-	$	-	$	17
Global equity securities		520		1,087		(9)		1,598
Fixed-income securities		1,059		75		(4)		1,130
Total nuclear decommissioning trusts (1)		1,596		1,162		(13)		2,745
Other investments		5		28		-		33
Total	$	1,601	$	1,190	$	(13)	$	2,778

(1)Represents amounts before deducting $314 million and $324 million at December 31, 2015 and2014, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of debt securities by contractual maturity is as follows:

	As of
(in millions)	December 31, 2015
Less than 1 year	$	18
1–5 years		470
5–10 years		273
More than 10 years		454
Total maturities of debt securities	$	1,215

The following table provides a summary of activity for the debt and equity securities:

	2015		2014		2013
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust
investments	$	1,268	$	1,336	$	1,619
Gross realized gains on sales of securities held as available-for-sale		55		118		94
Gross realized losses on sales of securities held as available-for-sale		(37)		(12)		(13)

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NOTE 11: EMPLOYEE BENEFIT PLANS

Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”).  The trusts underlying certain of these plans are qualified trusts under the Internal Revenue Code of 1986, as amended.  If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations.  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 is zero. 

PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.  PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans.

Change in Plan Assets, Benefit Obligations, and Funded Status

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2015 and 2014:

Pension Plan

(in millions)	2015		2014
Change in plan assets:
Fair value of plan assets at beginning of year	$	14,216	$	12,527
Actual return on plan assets		(176)		1,946
Company contributions		334		332
Benefits and expenses paid		(629)		(589)
Fair value of plan assets at end of year	$	13,745	$	14,216
Change in benefit obligation:
Benefit obligation at beginning of year	$	16,696	$	14,077
Service cost for benefits earned		479		383
Interest cost		673		695
Actuarial (gain) loss		(922)		2,131
Plan amendments		1		(1)
Transitional costs		1		-
Benefits and expenses paid		(629)		(589)
Benefit obligation at end of year (1)	$	16,299	$	16,696
Funded Status:
Current liability	$	(6)	$	(6)
Noncurrent liability		(2,547)		(2,474)
Net liability at end of year	$	(2,553)	$	(2,480)

(1)PG&E Corporation’s accumulated benefit obligation was $14.7billion and $14.9 billion at December 31, 2015 and 2014, respectively.

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Postretirement Benefits Other than Pensions

(in millions)	2015		2014
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,092	$	1,892
Actual return on plan assets		(26)		241
Company contributions		61		57
Plan participant contribution		68		63
Benefits and expenses paid		(160)		(161)
Fair value of plan assets at end of year	$	2,035	$	2,092
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,811	$	1,597
Service cost for benefits earned		55		45
Interest cost		71		76
Actuarial (gain) loss		(98)		166
Transitional costs		1		-
Benefits and expenses paid		(146)		(140)
Federal subsidy on benefits paid		4		4
Plan participant contributions		68		63
Benefit obligation at end of year	$	1,766	$	1,811
Funded Status: (1)
Noncurrent asset	$	344	$	368
Noncurrent liability		(75)		(87)
Net asset at end of year	$	269	$	281

(1) At December 31, 2015 and 2014, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.      

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

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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 was as follows:

Pension Plan

(in millions)	2015		2014		2013
Service cost	$	479	$	383	$	468
Interest cost		673		695		627
Expected return on plan assets		(873)		(807)		(650)
Amortization of prior service cost		15		20		20
Amortization of net actuarial loss		10		2		111
Net periodic benefit cost		304		293		576
Less: transfer to regulatory account (1)		34		42		(238)
Total expense recognized	$	338	$	335	$	338

(1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.

Postretirement Benefits Other than Pensions

(in millions)	2015		2014		2013
Service cost	$	55	$	45	$	53
Interest cost		71		76		74
Expected return on plan assets		(112)		(103)		(79)
Amortization of prior service cost		19		23		23
Amortization of net actuarial loss		4		2		6
Net periodic benefit cost	$	37	$	43	$	77

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 unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax.  In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions. For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income. For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income. As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss).

The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2016are as follows:

(in millions)	Pension Plan		PBOP Plans
Unrecognized prior service cost	$	8	$	15
Unrecognized net loss		24		4
Total	$	32	$	19

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.

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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 Plan						PBOP Plans
	December 31,						December 31,
	2015		2014		2013		2015		2014		2013
Discount rate	4.37	%	4.00	%	4.89	%	4.27 - 4.48	%	3.89 - 4.09	%	4.70 - 5.00	%
Rate of future compensation
increases	4.00	%	4.00	%	4.00	%	-		-		-
Expected return on plan
assets	6.10	%	6.20	%	6.50	%	3.20 - 6.60	%	3.30 - 6.70	%	3.50 - 6.70	%

The assumed health care cost trend rate as of December 31, 2015 was7.2%, decreasing gradually to an ultimate trend rate in 2024 and beyond of approximately 4%.  A one-percentage-point change in assumed health care cost trend rate would have the following effects:

	One-Percentage-Point		One-Percentage-Point
(in millions)	Increase		Decrease
Effect on postretirement benefit obligation	$	113	$	(114)
Effect on service and interest cost		9		(9)

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 of6.1% compares to a ten-year actual return of 7.8%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 688Aa-grade non-callable bonds at December 31,2015.  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.

Investment Policies and Strategies

The financial position of PG&E Corporation’s and the Utility’s 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 in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended.  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. 

The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings.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 trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields.  To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations inlong maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return.  Real assetsand 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, REITS, global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios.

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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.  Derivative instruments such as equity index futures are used to meet target equity exposure.  In addition, derivative instruments such as equity index futures and U.S. treasury futures are used 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 non U.S. dollar exposure of global equity investments.

The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:

	Pension Plan						PBOP Plans
	2016		2015		2014		2016		2015		2014
Global equity	25	%	25	%	25	%	32	%	31	%	30	%
Absolute return	5	%	5	%	5	%	3	%	3	%	3	%
Real assets	10	%	10	%	10	%	7	%	8	%	8	%
Fixed income	60	%	60	%	60	%	58	%	58	%	59	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

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.

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, 2015 and 2014. 

	Fair Value Measurements
	At December 31,
	2015								2014
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	247	$	369	$	-	$	616	$	352	$	311	$	-	$	663
Global equity		903		2,243		-		3,146		918		2,311		-		3,229
Absolute return		-		-		660		660		-		-		577		577
Real assets		581		-		753		1,334		620		-		675		1,295
Fixed-income		1,841		5,516		640		7,997		2,068		5,718		638		8,424
Total	$	3,572	$	8,128	$	2,053	$	13,753	$	3,958	$	8,340	$	1,890	$	14,188
PBOP Plans:
Short-term investments	$	20	$	-	$	-	$	20	$	28	$	-	$	-	$	28
Global equity		104		545		-		649		124		549		-		673
Absolute return		-		-		65		65		-		-		55		55
Real assets		69		-		77		146		72		-		49		121
Fixed-income		150		1,010		-		1,160		163		1,055		1		1,219
Total	$	343	$	1,555	$	142	$	2,040	$	387	$	1,604	$	105	$	2,096
Total plan assets at fair value							$	15,793							$	16,284

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $13 million and $24 million at December 31, 2015 and 2014, respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable.

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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.  All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days.

Short-Term Investments

Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets.

Global Equity

The global equity category includes investments in common stock, equity-index futures,and commingled funds comprised of equity securities spread 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 futuresare valued based on unadjusted prices in active markets and are Level 1 assets.  Commingled equity 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 equity 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 equity funds are categorized as Level 1 and 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 commodity futures, global REITS, global listed infrastructure equities, and private real estate funds.  The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore 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 ofcorporate debt instruments.  Commingled fundsare considered Level 2 assets.  Corporate fixed-income also includes privately placed debt portfolios which 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 onobservable 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 Treasury futures.  Municipal bonds are valued based on a compilation of primarily observable information or broker quotes in non-active markets and are considered Level 2 assets.  Futures are valued based on unadjusted prices in active markets and are Level 1 assets.

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Transfers Between Levels

Any transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period.  No material transfers between levels occurred in the years ended December 31, 2015 and 2014.

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, 2015 and 2014:

	Pension Plan
(in millions)	Absolute		Fixed-
For the year ended December 31, 2015	Return		Income		Real Assets		Total
Balance at beginning of year	$	577	$	638	$	675	$	1,890
Actual return on plan  assets:
Relating to assets still held at the reporting date		(7)		9		63		65
Relating to assets sold during the period		-		1		-		1
Purchases, issuances, sales, and settlements:
Purchases		90		2		17		109
Settlements		-		(10)		(2)		(12)
Balance at end of year	$	660	$	640	$	753	$	2,053
	Pension Plan
(in millions)	Absolute		Fixed-
For the year ended December 31, 2014	Return		Income		Real Assets		Total
Balance at beginning of year	$	554	$	625	$	544	$	1,723
Actual return on plan assets:
Relating to assets still held at the reporting date		23		24		54		101
Relating to assets sold during the period		-		4		-		4
Purchases, issuances, sales, and settlements:
Purchases		-		1		78		79
Settlements		-		(16)		(1)		(17)
Balance at end of year	$	577	$	638	$	675	$	1,890

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	PBOP Plans
(in millions)	Absolute		Fixed-
For the year ended December 31, 2015	Return		Income		Real Assets		Total
Balance at beginning of year	$	55	$	1	$	49	$	105
Actual return on plan  assets:
Relating to assets still held at the reporting date		(1)		-		5		4
Relating to assets sold during the period		-		-		-		-
Purchases, issuances, sales, and settlements:
Purchases		11		-		23		34
Settlements		-		(1)		-		(1)
Balance at end of year	$	65	$	-	$	77	$	142
	PBOP Plans
(in millions)	Absolute		Fixed-
For the year ended December 31, 2014	Return		Income		Real Assets		Total
Balance at beginning of year	$	53	$	2	$	38	$	93
Actual return on plan assets:
Relating to assets still held at the reporting date		2		-		4		6
Relating to assets sold during the period		-		-		-		-
Purchases, issuances, sales, and settlements:
Purchases		-		-		7		7
Settlements		-		(1)		-		(1)
Balance at end of year	$	55	$	1	$	49	$	105

There were no material transfers out of Level 3 in 2015 and 2014.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $334 million to the pension benefit plans and $61 million to the other benefit plans in 2015.  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 2015.  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 $61 million to the pension plan and other postretirement benefit plans, respectively, for 2016.

Benefits Payments and Receipts

As of December 31, 2015, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:

	Pension		PBOP		Federal
(in millions)	Plan		Plans		Subsidy
2016	$	695	$	89	$	(6)
2017		739		95		(7)
2018		780		101		(7)
2019		818		107		(8)
2020		854		113		(8)
Thereafter in the succeeding five years		4,728		593		(17)

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 also 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.

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Retirement Savings Plan

PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended.  This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants.  Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $89 million, $80 million, and $71 million in 2015, 2014, and 2013, respectively.

There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.

NOTE 12: 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:

	Year Ended December 31,
(in millions)	2015		2014		2013
Utility revenues from:
Administrative services provided to PG&E Corporation	$	6	$	5	$	7
Utility expenses from:
Administrative services received from PG&E Corporation	$	53	$	54	$	45
Utility employee benefit due to PG&E Corporation		82		70		57

At December 31, 2015and 2014, the Utility had receivables of $22 million and $17 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 $21 million and $20 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

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NOTE 13: CONTINGENCIES AND COMMITMENTS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation has financial commitments described in “Other Commitments” below.

Enforcement and Litigation Matters

CPUC Matters

Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

During 2014 and 2015, the Utility filed several reports to notify the CPUC of communications that the Utility believes may have constituted or described ex parte communications that either should not have been made or that should have been timely reported to the CPUC. Ex parte communications include communications between a decision maker or a Commissioner’s advisor and interested persons concerning substantive issues in certain formal proceedings. Certain communications are prohibited and others are permissible with proper noticing and reporting.

On November 23, 2015, the CPUC issued an OII into whether the Utility should be sanctioned for violating rules pertaining to ex parte communications and Rule 1.1 of the CPUC’s Rules of Practice and Procedure governing the conduct of those appearing before the CPUC.  The OII cites some of the communications the Utility reported to the CPUC.  The OII also cites the ex parte violations alleged in the City of San Bruno’s July 2014 motion, which it filed in the CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices.  A prehearing conference in the OII has been scheduled for March 1, 2016.

The CPUC will determine any penalties that might be imposed on the Utility and determine whether shareholders or ratepayers will bear the costs of the investigation. The CPUC can impose fines up to $50,000 for each violation, per day.The CPUC haswide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as how many days each violation continued; 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.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the OII but they are unable to reasonably estimate the amount or range of future charges that could be incurred, because it is uncertain how the CPUC will calculate the number of violations or the penalty for any violations, and whether the CPUC will consider additional communications in the OII, including those identified in a motion filed on December 1, 2015, by the City of San Bruno in the 2015 GT&S rate case.  It is also uncertain whether the CPUC will take additional action in any of the proceedings in which the Utility has self-reported communications that may have violated the CPUC’s ex parte rules.

Finally, the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office also have been investigating matters related to allegedly improper communications between the Utility and CPUC personnel. The Utility is cooperating with the federal and state investigators. It is uncertain whether any charges will be brought against the Utility.

CPUC Investigation Regarding Natural Gas Distribution FacilitiesRecord-Keeping

On November 20, 2014, the CPUC began an investigation into whether the Utility violated applicable laws pertaining to record-keeping practices with respect to maintaining safe operation of its natural gas distribution service and facilities.  The order also requires the Utility to show cause why (1) the CPUC should not find that the Utility violated provisions of the California Public Utilities Code, CPUC general orders or decisions, other rules, or requirements, and/or engaged in unreasonable and/or imprudent practices related to these matters, and (2) the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found.  In particular, the order cites the SED’s investigative reports alleging that the Utility violated rules regarding safety record-keeping in connection with six natural gas distribution incidents, including the natural gas explosion that occurred in Carmel, California on March 3, 2014, for which the CPUC has previously imposed a penalty of $10.85 million. 

On September 30, 2015, the SED submitted its supplemental testimony, which included incidents allegedly related to record-keeping that had not been identified in the initial order, and also asserted violations related to the Utility’s pre-excavation location and marking practices, causal evaluation practices, and compliance with regulations governing pressure validation for certain distribution facilities.  Evidentiary hearings were held during January 2016.  Opening briefs are due by February 26, 2016 and reply briefs are due by March 31, 2016.  The SED has indicated it will seek significant penalties, the amount of which is expected to be disclosed in its brief.

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PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the form of fines or other remedies, including possible future unrecoverable costs to implement operational remedies. The Utility is unable to determine the form or amount of penalties or reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion (discussed above).

Natural Gas Transmission Pipeline Rights-of-Way   

In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey has been completed and that remediation work, including removal of the encroachments, is expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility or take other enforcement action in the future based on the Utility’s failure to continuously survey its system and remove encroachments.  The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties.

Potential Safety Citations

The SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations.In addition, the California utilities are required to inform the SED of self-identified or self-corrected violations. The CPUC has delegated authority to the SED to issue citations and impose fines for violations identified through audits, investigations, or self-reports. The SED can consider the discretionary factors discussed above (see “Order Instituting an Investigation into Compliance with Ex parte Communication Rules” above) in determining the number of violations and whether to impose daily fines for continuing violations. The SED is required, however, to impose the maximum statutory penalty of $50,000 for each separate violation.

The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations. The Utility believes it is probable that the SED will impose fines or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines imposed by the SED with respect to these matters given the wide discretion the SED has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.

Federal Matters

Federal Criminal Indictment

On July 29, 2014, a federal grand jury for the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court that superseded the original indictment that was returned on April 1, 2014.  The superseding indictment charges 27 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats.  The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident.  On December 23, 2015, the court presiding over the federal criminal proceeding dismissed 15 of the Pipeline Safety Act counts, leaving 13remaining counts.  The maximum statutory fine for each felony count is $500,000, for total potential fines of $6.5 million. On December 8, 2015, the court alsoissued an order granting, in part, the Utility’s request to dismiss the government’s allegations seeking an alternative fine under the Alternative Fines Act. The Alternative Fines Act states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.”The court dismissed the government’s allegations regarding the amount of losses, but concluded that it required additional information about how the government would prove its allegations about the amount of gross gains prior to deciding whether to dismiss those allegations.  (Based on the superseding indictment’s allegation that the Utility derived gross gains of approximately $281 million, the potential maximum alternative fine would be approximately $562 million.)After considering the additional information submitted by the government, on February 2, 2016, the court issued an order holding that if the government’s allegations about the Utility’s gross gains are considered, they would be considered in a second trial phase that would take place after the trial on the criminal charges.The trial on the criminal charges currently is scheduled to begin March 22, 2016.

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The Utility entered a plea of not guilty.The Utility believes that criminal charges and the alternative fine allegations are not merited and that it did not knowingly and willfully violate minimum safety standards under the Natural Gas Pipeline Safety Act or obstruct the NTSB’s investigation, as alleged in the superseding indictment.  PG&E Corporation and the Utility have not accrued any charges for criminal fines in their Consolidated Financial Statements as such amounts are not considered to be probable.

Other Federal Matters

The Utility was informed that the U.S. Attorney’s Office wasinvestigating a natural gas explosion that occurred in Carmel, California on March 3, 2014. The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case discussed above. It is uncertain whether any additional charges will be brought against the Utility.

Capital Expenditures Relating to Pipeline Safety Enhancement Plan

At December 31, 2015, approximately $664 million of PSEP-related capital costs is recorded in property, plant, and equipment on the Consolidated Balance Sheets. The Utility would be required to record charges to the statement of income in future periods to the extent total forecasted PSEP-related capital costs are higher than currently expected.

Penalty Decision Related to the CPUC’s Investigative Enforcement Proceedings Related to Natural Gas Transmission

On April 9, 2015, the CPUC approved final decisions in the three investigations that had been brought against the Utility relating to (1) the Utility’s safety record-keeping 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, record-keeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010.  A decision was issued in each investigative proceeding to determine the violations that the Utility committed.  The CPUC also approved a fourth decision (the “Penalty Decision”) which imposes penalties on the Utility totaling $1.6 billion comprised of: (1) a $300 million fine to be paid to the State General Fund, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million. In August 2015, the Utility paid the $300 million fine. At December 31, 2015, the Consolidated Balance Sheets include $400 million in current regulatory liabilities for the one-time bill credit that will be provided to the Utility’s natural gas customers in 2016.  On January 14, 2016, the CPUC issued final decisions to close these investigative proceedings.

The Penalty Decision requires that at least $689 million of the $850 million disallowance be allocated to capital expenditures, and that the Utility be precluded from including these capital costs in rate base.  The CPUC will determine which safety projects and programs will be funded by shareholders in the Utility’s pending 2015 GT&S rate case.  If the $850 million is not exhausted by designated safety-related projects and programs in the 2015 GT&S proceeding, the CPUC will identify additional projects in future proceedings to ensure that the full $850 million is spent. The CPUC is expected to issue a final decision in the Utility’s 2015 GT&S rate case in 2016 to identify safety-related projects and programs that will be subject to the disallowance. It is uncertain how much of the Utility’s costs to perform the safety-related projects and programs the CPUC will identify as counting toward the $850 million shareholder-funded obligation. If the Utility’s actual costs exceed costs that the CPUC counts towards the $850 million maximum, the Utility would record additional charges if such costs are not otherwise authorized by the CPUC.  As a result, the total shareholder-funded obligation could exceed $850 million. 

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For the year ended December 31, 2015, the Utility recorded additional charges in operating and maintenance expenses in the Consolidated Statements of Income of $907 million as a result of the Penalty Decision. The cumulative charges at December 31, 2015, and the additional future charges to reach the $1.6 billion total are shown in the following table:

	Year		Cumulative		Future
	Ended		Charges		Charges
	December 31,		December 31,		and		Total
(in millions)	2015		2015		Costs		Amount
Fine payable to the state (1)	$	100	$	300	$	-	$	300
Customer bill credit		400		400		-		400
Charge for disallowed capital (2)		407		407		282		689
Disallowed revenue for pipeline safety
expenses (3)		-		-		161		161
CPUC estimated cost of other remedies (4)		-		-		-		50
Total Penalty Decision fines and remedies	$	907	$	1,107	$	473	$	1,600

(1) In March 2015, the Utility increased its accrual from $200 million at December 31, 2014 to $300 million.

(2) The Penalty Decision prohibits the Utility from recovering certain expenses and capital spending associated with pipeline safety-related projects and programs that the CPUC will identify in the final decision to be issued in the Utility’s 2015 GT&S rate case.The Utility estimates that approximately $407 million of capital spending (which include less than $1 million for remedy related capital costs) in the year ended December 31, 2015 is probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision.

(3) These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses.

(4)In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision and does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs are being expensed as incurred.

Other Legal and Regulatory Contingencies

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits.  In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations.  A provision for a loss contingency is recorded 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.  The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred.

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Investigation of the Butte Fire

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. The California Department of Forestry and Fire Protection (“Cal Fire”) is investigating the source of the Butte Fire to determine whether a tree contacted a power line operated by the Utility and was the cause of the fire.  Cal Fire has reported that as a result of the fire there were two deaths and 965 structures, including 571 houses, were damaged or destroyed. Cal Fire’s investigation is expected to conclude in 2016.

Approximately 27 complaints have been filed against the Utility and its vegetation management contractors in the Superior Court of California in both the County of Calaveras and the County of San Francisco, involving more than 600 individual plaintiffs and their insurance companies. Plaintiffs and the Utility filed petitions with the California Judicial Council to coordinate these cases.  The petitions were assigned to the Calaveras Superior Court for a recommendation to the Judicial Council.  On January 21, 2016, the Calaveras Superior Court issued an order recommending to the Judicial Council that the cases be coordinated in the Superior Court of California, Sacramento County, for all purposes including trial.  Among other factors, the Court found that coordination requires a court with a significant number of judges and complex litigation support personnel, neither of which are present in Calaveras County.

It is estimated that losses related to structures, contents, other personal property, and fire suppression costs associated with the Butte fire, will range from $350 million to $450 million.  This range is based on estimates about the number, size, and type of structures damaged or destroyed, assumptions about the contents of such structures and other personal property damage, and information about the amount of fire suppression costs associated with prior similar fires.  The Utility believes that it is reasonably possible that it would be liable for some or all of these and other costs, such as costs associated with tree damage, personal injury, business interruption losses, and other damages.  The Utility is unable to reasonably estimate these other costs at this time due to the limited information available.

The Utility has insurance coverage for these types of claims. If the amount of insurance is insufficient to cover the Utility's liability resulting from the Butte fire, or if insurance is otherwise unavailable, PG&E Corporation’s and the Utility’s financial condition or results of operations could be materially affected.

Rehearing of CPUC Decisions Approving Energy Efficiency Incentive Awards

On September 17, 2015, the CPUC issued an order granting TURN’s and the ORA’s long-standing applications for rehearing of the CPUC decisions that awarded energy efficiency incentive payments to the California investor-owned utilities for the 2006-2008 energy efficiency program cycle. Under the ratemaking mechanism applicable to the 2006-2008 program cycle, the maximum amount of incentives that the Utility could have earned (or the maximum amount that the Utility could have been required to reimburse customers) over the 2006-2008 program cycle was $180 million. The Utility was awarded a total of $104 million for the 2006-2008 program cycle. In the re-opened energy efficiency proceeding, the CPUC will evaluate whether incentives awarded to the California investor-owned utilities were just and reasonable, and whether any refunds are due.  The parties are required to submit proposals to resolve the issues in the proceeding by March 18, 2016. Comments on the proposals are due on April 8, 2016 and evidentiary hearings, if needed, would be held in July 2016. It is uncertain when the CPUC will issue a decision and whether the Utility will be required to refund amounts or incur other obligations related to the 2006-2008 program cycle. PG&E Corporation and the Utility believe it is reasonably possible that the Utility will be required to refund amounts or incur other obligations related to this matter, but they are unable to reasonably estimate the amount of such refunds or other obligations.

Other Contingencies

Accruals for other legal and regulatory contingencies (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters” and “Other Legal and Regulatory Contingencies”) totaled $63 million at December 31, 2015, and $55 million at December 31, 2014.  These amounts are included in other current liabilities in the Consolidated Balance Sheets.  The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

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Environmental Remediation Contingencies

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 the 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 Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is composed of the following:

	Balance at
(in millions)	December 31, 2015		December 31, 2014
Topock natural gas compressor station (1)	$	300	$	291
Hinkley natural gas compressor station (1)		140		158
Former manufactured gas plant sites owned by the Utility or third parties		271		257
Utility-owned generation facilities (other than fossil fuel-fired),   other facilities, and third-party disposal sites		164		150
Fossil fuel-fired generation facilities and sites		94		98
Total environmental remediation liability	$	969	$	954

(1) See “Natural Gas Compressor Station Sites” below.

At December 31, 2015 the Utility expected to recover $695 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC.  One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites (including the Topock site) without a reasonableness review. The Utility may incur environmental remediation costs that it does not seek to recover in rates, such as the costs associated with the Hinkley site.

Natural Gas Compressor Station Sites

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past atthe Utility’s natural gas compressor stations.  One of these stations is located near Hinkley, California and is referred to below as the “Hinkley site.”  Another station is located near Needles, California and is referred to below as the “Topock site.” The Utility is also required to take measures to abate the effects of the contamination on the environment.

Hinkley Site

The Utility has been implementing interim remediation measures at the Hinkley site to reduce the mass of the chromium plume and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the Regional Board.On November 4, 2015, the Regional Board adopted a final clean-up and abatement order to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts.  The final order states that the Utility must continue and improve its remediation efforts; define the boundaries of the chromium plume, and take other action.  Additionally, the final order requires setting plume capture requirements, requires establishing a monitoring and reporting program, and finalizes deadlines for the Utility to meet interim cleanup targets.  The clean-up and abatement order did not have a material impact on the Utility’s consolidated financial statements.

The Utility’s environmental remediation liability at December 31, 2015 reflects the Utility’s best estimate of probable future costs associated with its final remediation plan.Future costs will depend on many factors, including the extent of work to be performed to implement the final remediation plan and the Utility’s required time frame for remediation.  Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition and cash flows.

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Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California Department of Toxic Substances Control and the U.S. Department of the Interior.  In November 2015, the Utility submitted its final remediation design to the agencies for approval.  The Utility’s design proposes that the Utility construct an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium.  The DTSC is conducting an additional environmental review of the proposed design, and the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in July 2016.  After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in December 2016.  After the Utility modifies its design in response to the final report, the Utility plans to seek approval to begin construction of the new in-situ treatment system in early 2017.

The Utility’s environmental remediation liability at December 31, 2015 reflects its best estimate of probable future costs associated with its final remediation plan.  Future costs will depend on many factors, including the extent of work to be performed to implement the final groundwater remedy and the Utility’s required time frame for remediation.  Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition and cash flows.

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 $1.9 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.  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 results of operations during the period in which they are recorded.

Nuclear Insurance

The Utility is a member of 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 if a nuclear event were to occur 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 $3.5billion per nuclear incident and $2.8 billion per non-nuclear incident for Diablo Canyon.  Humboldt Bay Unit 3 has up to $131 million of coverage for nuclear and non-nuclear property damages.  If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment.  If NEIL were to exercise this assessment, as of December 31, 2015, the current maximum aggregate annual retrospective premium obligation for the Utility is approximately $60 million.

NEIL also provides 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 $3.5 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 $3.5 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 $13.5 billion.  The Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon.  The balance of the $13.5 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors.  The Utility may be assessed up to $255 million per nuclear incident under this program, with payments in each year limited to a maximum of $38 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 September 10, 2018.

The Price-Anderson Act does not apply to 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.  The Utility has a separate 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 liability insurance.

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Resolution of Remaining Chapter 11 Disputed Claims

Various electricity suppliers filed claims in the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers 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 California Power Exchange wholesale electricity markets during this period. 

At December 31, 2015, and December 31, 2014, the Consolidated Balance Sheets reflected $454 million and $434 million, respectively, in net Disputed claims and customer refunds, including both principal and interest.At December 31, 2015 and 2014, the Utility held $228 million and $291 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 liability 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 liability, 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 liability and when such interest is paid.

While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers.  The Utility has 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.  Under these settlement agreements, 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.  Any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods.

In July 2014, a settlement agreement between the Utility and an electric supplier became effective, resolving a portion of the Utility’s net disputed claims and resulting in refunds to customers of $312 million.  No significant settlement agreements were reached in 2015.  The Utility is uncertain when and how the remaining net disputed claims liability will be resolved.

Purchase Commitments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2015:

	Power Purchase Agreements
	Renewable		Conventional				Natural		Nuclear
(in millions)	Energy		Energy		Other		Gas		Fuel		Total
2016	$	2,177	$	772	$	504	$	421	$	113	$	3,987
2017		2,201		787		380		150		100		3,618
2018		2,075		706		359		105		96		3,341
2019		2,087		694		290		105		98		3,274
2020		2,077		674		213		103		133		3,200
Thereafter		29,098		1,729		997		543		185		32,552
Total purchase
commitments	$	39,715	$	5,362	$	2,743	$	1,427	$	725	$	49,972

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Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements,including renewable energy agreements, QF agreements, and other power purchase 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.

Renewable Energy Power Purchase Agreements.  In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow significantly.  As of December 31, 2015, renewable energy contracts expire at various dates between 2016 and 2043.

Conventional Energy Power Purchase Agreements.  The Utility has entered into many power purchase agreements for conventionalgeneration 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.  As of December 31, 2015, these power purchase agreements expire at various dates between 2016 and 2033.

Other Power Purchase Agreements.  The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law.  Several of these agreements are treated as capital leases.  At December 31, 2015 and 2014, net capital leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $54 million and $74 million including accumulated amortization of $147 million and $128 million, respectively.  The present value of the future minimum lease payments due under these agreements included $19 million and $20 million in Current Liabilities and $35 million and $54 million in Noncurrent Liabilities on the Consolidated Balance Sheet, respectively.As of December 31, 2015, QF contracts in operationexpire at various dates between 2016and2028.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The costs incurred for all power purchases and electric capacity amounted to $3.5 billion in 2015, $3.6 billion in 2014, and $3.0 billion in 2013.

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.  These agreements expire at various dates between 2016 and 2026.  In addition, the Utility has contracted for natural gas storage services in northern California in order to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $0.9 billion in 2015, $1.4 billion in 2014, and $1.6 billion in 2013.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between2016and2025 and are intended to ensure long-term nuclear fuel supply.  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. 

Payments for nuclear fuel amounted to $128 million in 2015, $105 million in 2014, and $162 million in 2013.

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Other Commitments

PG&E Corporation and the Utility have other commitments related to operating leases (primarily office facilities and land), which expire at various dates between 2016 and2052.  At December 31, 2015, the future minimum payments related to these commitments were as follows:

(in millions)	Operating Leases
2016	$	40
2017		41
2018		40
2019		38
2020		37
Thereafter		194
Total minimum lease payments	$	390

Payments for other commitments related to operating leases amounted to $41million in 2015, $42 million in 2014, and $40 million in 2013.  Certain leases on office facilities contain escalation clauses requiring annual increases in rent.  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 operations ranging between one and five years.

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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
2015
PG&E CORPORATION
Operating revenues	$	4,167	$	4,550	$	4,217	$	3,899
Operating income		205		545		687		71
Income tax (benefit) provision (1)		(111)		67		110		(93)
Net income (2)		138		310		406		34
Income available for common shareholders		134		307		402		31
Comprehensive income		137		310		406		17
Net earnings per common share, basic		0.27		0.63		0.84		0.06
Net earnings per common share, diluted		0.27		0.63		0.83		0.06
Common stock price per share:
High		54.50		54.41		54.27		60.15
Low		51.65		47.60		49.10		51.38
UTILITY
Operating revenues	$	4,167	$	4,550	$	4,216	$	3,900
Operating income		208		544		687		72
Income tax (benefit) provision (1)		(114)		72		115		(92)
Net income (2)		147		305		406		4
Income available for common stock		143		302		402		1
Comprehensive income		145		305		406		4
2014
PG&E CORPORATION
Operating revenues (3)	$	4,308	$	4,939	$	3,952	$	3,891
Operating income		383		1,065		518		484
Income tax provision		35		115		104		91
Net income (4)		135		814		271		230
Income available for common shareholders		131		811		267		227
Comprehensive income		120		796		260		235
Net earnings per common share, basic		0.28		1.72		0.57		0.49
Net earnings per common share, diluted		0.27		1.71		0.57		0.49
Common stock price per share:
High		54.98		48.07		48.23		44.73
Low		44.38		43.00		42.37		39.60
UTILITY
Operating revenues (3)	$	4,308	$	4,939	$	3,951	$	3,890
Operating income		383		1,059		525		485
Income tax provision		59		115		110		100
Net income (4)		162		793		250		228
Income available for common stock		158		790		246		225
Comprehensive income		154		793		250		228

(1) In the first quarter of 2015, the Utility had an income tax benefit, primarily due to the impact of the Penalty Decision. (See note (2) below.)  In the fourth quarter of 2015, the Utility had an income tax benefit, primarily due to lower income before taxes and an audit settlement received.

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(2)In the first quarter of 2015, the Utility recorded total charges of $553 million related to the Penalty Decision, including $53 million in estimated capital spending that is probable of disallowance.  In the second, third, and fourth quarters of 2015, the Utility recorded $75 million, $142 million, and $137 million, respectively, in estimated capital spending that is probable of disallowance.  (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

(3) In the third quarter of 2014, the Utility recorded an increase to base revenues as authorized by the CPUC in the 2014 GRC decision.

(4)The Utility recorded charges to net income of $116 million in the fourth quarter of 2014 for PSEP capital costs that are forecasted to exceed the authorized amounts.  (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

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MANAGEMENT’S REPORTON INTERNAL CONTROL OVERFINANCIAL REPORTING

Management of PG&E Corporation and 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, 2015, based on the criteria established in Internal Control—Integrated Framework (2013) 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, 2015.

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 December31, 2015, based on criteria established in Internal Control— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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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, 2015, based on criteria established in Internal Control — Integrated Framework (2013)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, 2015, based on the criteria established in Internal Control — Integrated Framework (2013)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, 2015of the Company and the Utility and our report dated February 18, 2016 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 18, 2016

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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, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

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, 2015, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 18, 2016 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 18, 2016

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ITEM9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not applicable.

ITEM9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of December31, 2015, 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 (i) recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms, and (ii) 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.

Management’s Annual Report on 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 Item 8 of this report under the heading “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm.”

Registered Public Accounting Firm’s Report on Internal Control over Financial Reporting

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 December31, 2015, based on criteria established in Internal Control— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Changes in Internal Control Over Financial Reporting

There were no changes in internal control over financial reporting that occurred during the quarter ended December31, 2015 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

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 2016 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 “Section16(a) Beneficial Ownership Reporting Compliance” in the Joint Proxy Statement relating to the 2016 Annual Meetings of Shareholders, which information is incorporated herein by reference.

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

The following documents are available both on PG&E Corporation’s websitewww.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 Form8-K filed within four business days of the waiver.

Procedures for Shareholder Recommendations of Nominees to the Boards of Directors

During 2015, there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2015Annual 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 – Audit Committees” and “Corporate Governance – Committee Membership” in the Joint Proxy Statement relating to the 2016 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 - 2015,” “Grants of Plan-Based Awards in 2015,” “Outstanding Equity Awards at Fiscal Year End - 2015,” “Option Exercises and Stock Vested During 2015,” “Pension Benefits – 2015,” “Non-Qualified Deferred Compensation – 2015,”“Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” and “Compensation of Non-Employee Directors – 2015Director Compensation” in the Joint Proxy Statement relating to the 2016Annual Meetings of Shareholders, which information is incorporated herein by reference.

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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 “Share Ownership Information – Security Ownership of Management” and “Share Ownership Information – Principal Shareholders” in the Joint Proxy Statement relating to the 2016 Annual Meetings of Shareholders, which information is incorporated herein by reference.

Equity Compensation Plan Information

The following table provides information as of December31, 2015 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation's existing equity compensation plans.

	(a)			(b)		(c)
Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights			Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
Equity compensation plans approved by shareholders	6,027,349	(1)	$	35.53	(2)	15,674,803	(3)
Equity compensation plans not approved by shareholders	-			-		-
Total equity compensation plans	6,027,349	(1)	$	35.53	(2)	15,674,803	(3)

(1) Includes 30,020 phantom stock units, 2,335,148 restricted stock units and 3,658,091 performance shares.  The weighted average exercise price reported in column (b) does not take these awards into account.  For performance shares, amounts reflected in this table assume payout in shares at 200% of target or, for performance shares granted in 2013, reflects the actual payout percentage of 50%.  The actual number of shares issued can range from 0% to 200% of target depending on achievement of performance 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) This is the weighted average exercise price for the 4,090 options outstanding as of December 31, 2015.

(3) Represents the total number of shares available for issuance under all of PG&E Corporation’s equity compensation plans as of December 31, 2015. Stock-based awards granted under these plans include restricted stock units, performance shares and phantom stock units.  The 2014 LTIP, which became effective on May 12, 2014, authorizes up to 17 million shares to be issued pursuant to awards granted under the 2014 LTIP, less approximately 2.7 million shares for awards granted under the 2006 LTIP from January 1, 2014 through May 11, 2014.  In addition, if any awards outstanding under the 2006 LTIP at December 31, 2013 are cancelled, forfeited or expire without being settled in full, shares of stock allocable to the terminated portion of such awards shall again be available for issuance under the 2014 LTIP.

For more information, see Note 5 of the Notes to the Consolidated Financial Statementsin Item 8.

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“Corporate Governance – Board and Director Independence and Qualifications” and “Corporate Governance – Committee Membership” in the Joint Proxy Statement relating to the 2016 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 2016 Annual Meetings of Shareholders, which information is incorporated herein by reference.

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PART IV

ITEM15.Exhibits and Financial Statement Schedules

1. 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 filed as part of this report in Item 8:

Consolidated Statements of Income for the Years Ended December31, 2015, 2014, and 2013 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2015, 2014, and 2013 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Balance Sheets at December31, 2015 and 2014 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014, and 2013 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Equity for the Years Ended December31, 2015, 2014, and 2013 for PG&E Corporation.

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2015, 2014, and 2013 for Pacific Gas and Electric Company.

Notes to the Consolidated Financial Statements.

Quarterly Consolidated Financial Data (Unaudited).

Management’s Report on Internal Controls

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

2. The following financial statement schedules are filed as part of this report:

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

I—Condensed Financial Information of Parent as of December31, 2015 and 2014 and for the Years Ended December31, 2015, 2014, and 2013.

II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December31, 2015, 2014, and 2013.

3. Exhibits required by Item 601 of RegulationS-K

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Exhibit Number	Exhibit Description
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 February 19, 2014 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 3.1)
3.4	Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April12, 2004 (File No.1-2348), Exhibit 3)
3.5	Bylaws of Pacific Gas and Electric Company amended as of August 17, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on July 14, 2015 (File No. 1-2348), Exhibit 99.2)
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), Exhibit4.1)
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 December4, 2007 relating to the Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes due November30, 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 November18, 2008 relating to the Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25% Senior Notes due December1, 2013 and $200million principal amount of its 8.25% Senior Notes due October15, 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 March6, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March1, 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 November18, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January15, 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 January15, 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)

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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 May15, 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	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)
4.15	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)
4.16	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)
4.17	Nineteenth Supplemental Indenture dated as of June 14, 2013 relating to the issuance of $375,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due June 15, 2023 and $375,000,000 aggregate principal amount of its 4.60% Senior Notes due June 15, 2043(incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 14, 2013 (File No. 1-2348), Exhibit 4.1)
4.18	Twentieth Supplemental Indenture dated as of November 12, 2013 relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.85% Senior Notes due November 15, 2023 and $500,000,000 aggregate principal amount of its 5.125% Senior Notes due November 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2013 (File No. 1-2348), Exhibit 4.1)
4.19	Twenty-First Supplemental Indenture, dated as of February 21, 2014, relating to the issuance of $450,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due February 15, 2024 and $450,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 21, 2014 (File No.12348), Exhibit 4.1)
4.20	Twenty-Third Supplemental Indenture, dated as of August 18, 2014, relating to the issuance of $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.40% Senior Notes due August 15, 2024 and $225,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 18, 2014 (File No. 1-2348), Exhibit 4.1)

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4.21	Twenty-Fourth Supplemental Indenture, dated as of November 6, 2014, relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 6, 2014 (File No. 1-2348), Exhibit 4.1)
4.22	Twenty-Fifth Supplemental Indenture, dated as of June 12, 2015, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 and $100,000,000 aggregate principal amount of its 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on June 12, 2015 (File No. 1-2348), Exhibit 4.1)
4.23	Twenty-Sixth Supplemental Indenture, dated as of November 5, 2015, relating to the issuance of $200,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 and $450,000,000 aggregate principal amount of its 4.25% Senior Notes due March 15, 2046 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on November 5, 2015 (File No. 1-2348), Exhibit 4.1)
4.24	Senior Note Indenture, dated as of February 10, 2014, between PG&E Corporation and U.S. Bank National Association (incorporated by reference to PG&E Corporation’s Form S-3 (File No. 333-193880), Exhibit 4.1)
4.25	First Supplemental Indenture, dated as of February 27, 2014, relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 2.40% Senior Notes due March 1, 2019 (incorporated by reference to PG&E Corporation’s Form 8-K dated February 27, 2014 (File No. 1-12609), Exhibit 4.1)
10.1	Second Amended and Restated Credit Agreement dated as of April 27, 2015, among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and Wells Fargo Securities LLC, as joint lead arrangers and joint bookrunners, (4) Citibank N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association, as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank, National Association, MUFG Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.1)
10.2	Second Amended and Restated Credit Agreement dated as of April 27, 2015, among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and Wells Fargo Securities LLC, as joint lead arrangers and joint bookrunners, (4) Bank of America, N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association, as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, MUFG Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-2348), Exhibit 10.2)
10.3	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)
10.4	Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March31, 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)

140

10.5	*	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)
10.6	*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015(File No. 1-12609), Exhibit 10.7)
10.7	*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2014 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, 2014(File No. 1-12609), Exhibit 10.4)
10.8	*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 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, 2013 (File No. 1-12609), Exhibit 10.5)
10.9	*	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)
10.10	*	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)
10.11	*	Performance Share Agreement subject to financial goals between Anthony F. Earley, Jr. and PG&E Corporation for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015(File No. 1-12609), Exhibit 10.8)
10.12	*	Performance Share Agreement subject to safety and customer affordability goals between Anthony F. Earley, Jr. and PG&E Corporation for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015(File No. 1-12609), Exhibit 10.9)
10.13	*	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2014 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, 2014(File No. 1-12609), Exhibit 10.5)
10.14	*	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 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, 2013 (File No. 1-12609), Exhibit 10.6)
10.15	*	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)
10.16	*	Restricted Stock Unit Agreement between Nickolas Stavropoulos and PG&E Corporation for additional 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan
10.17	*	Restricted Stock Unit Agreement between Geisha J. Williams and PG&E Corporation for additional 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan
10.18	*	Restricted Stock Unit Agreement between John R. Simon and PG&E Corporation for additional 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan
10.19	*	Letter regarding Compensation Agreement between PG&E Corporation and Julie M. Kane dated March 11, 2015 for employment starting May 18, 2015 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 (File No. 1-2348), Exhibit 10.4)
10.20	*	Restricted Stock Unit Agreement between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 (File No. 1-2348), Exhibit 10.5)

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10.21	*	Non-Annual Restricted Stock Unit Agreement between Julie M. Kane and PG&E Corporation dated May 29, 2015 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 (File No. 1-2348), Exhibit 10.6)
10.22	*	Performance Share Agreement subject to financial goals between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 (File No. 1-2348), Exhibit 10.7)
10.23	*	Performance Share Agreement subject to safety and customer affordability goals between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 (File No. 1-2348), Exhibit 10.8)
10.24	*	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)
10.25	*	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)
10.26	*	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)
10.27	*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Nickolas 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)
10.28	*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Steven Malnight dated February 22, 2012(incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2014 (File No. 1-2348), Exhibit 10.3)
10.29	*	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)
10.30	*	PG&E Corporation 2005 Supplemental Retirement Savings Plan, as amended effective September 15, 2015 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2015 (File No.1-12609), Exhibit10.3)
10.31	*	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), Exhibit10.24)
10.32	*	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)
10.33	*	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2015(incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.3)
10.34	*	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), Exhibit10.27)
10.35	*	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), Exhibit10.28)

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10.36	*	PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of January 1, 2013 (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)
10.37	*	PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective September 17, 2013 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2013 (File No.1-12609), Exhibit10.2)
10.38	*	Pacific Gas and Electric Company Relocation Assistance Program for Officers
10.39	*	Amendment to the Postretirement Life Insurance Plan of the Pacific Gas and Electric Company, effective February 6, 2015(incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2014) (File No. 1-12609), Exhibit 10.37)
10.40	*	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), Exhibit10.7)
10.41	*	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)
10.42	*	PG&E Corporation 2014 Long-Term Incentive Plan effective May 12, 2014 and amended effective January 1, 2016
10.43	*	PG&E Corporation 2006 Long-Term Incentive Plan, as amended effective January 1, 2013 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2012(File No.1-12609), Exhibit10.40)
10.44	*	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), Exhibit10)
10.45	*	Form of Restricted Stock Unit Agreement for 2015 grants to directors under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2015 (File No. 1-12609), Exhibit 10.3)
10.46	*	Form of Restricted Stock Unit Agreement for 2015 grants under the PG&E Corporation 2014 Long-Term Incentive Plan(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.4)
10.47	*	Form of Restricted Stock Unit Agreement for 2014 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, 2014 (File No.1-12609), Exhibit10.2)
10.48	*	Form of Restricted Stock Unit Agreement for 2013 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, 2013 (File No.1-12609), Exhibit10.3)
10.49	*	Form of Restricted Stock Unit 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), Exhibit10.1)
10.50	*	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), Exhibit10.1)
10.51	*	Form of Restricted Stock Unit Agreement for 2014 grants to directors under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2014 (File No.1-12609), Exhibit10.3)
10.52	*	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 January6, 2005 (File No.1-12609 and File No.1-2348), Exhibit99.1)

143

10.53	*	Form of Performance Share Agreement subject to financial goals for 2015 grants under the PG&E Corporation 2014 Long-Term Incentive Plan(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.5)
10.54	*	Form of Performance Share Agreement subject to safety and customer affordability goals for 2015 grants under the PG&E Corporation 2014 Long-Term Incentive Plan(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.6)
10.55	*	Form of Performance Share Agreement for 2014 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, 2014(File No.1-12609), Exhibit10.3)
10.56	*	Form of Performance Share Agreement for 2013 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, 2013 (File No.1-12609), Exhibit10.4)
10.57	*	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), Exhibit10.2)
10.58	*	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), Exhibit10.3)
10.59	*	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), Exhibit10.2)
10.60	*	PG&E Corporation 2012 Officer Severance Policy, as amended effective as of May 12, 2014 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2014 (File No.1-12609), Exhibit10.2)
10.61	*	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), Exhibit10.5)
10.62	*	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), Exhibit10.49)
10.63	*	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), Exhibit10.58)
10.64	*	Amended and Restated PG&E Corporation Director Grantor Trust Agreement dated October 1, 2015 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2015 (File No. 1-12609), Exhibit 10.1)
10.65	*	Amended and Restated PG&E Corporation Officer Grantor Trust Agreement dated October 1, 2015 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2015 (File No. 1-12609), Exhibit 10.2)
10.66	*	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), Exhibit10.54)
10.67	*	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), Exhibit10.40)
10.68	*	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), Exhibit10.41)
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

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

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SIGNATURES

Pursuant to the requirements of Section13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form10-K for the year ended December31, 2015 to be signed on their behalf by the undersigned, thereunto duly authorized.

	PG&E CORPORATION		PACIFIC GAS AND ELECTRIC COMPANY
	(Registrant)		(Registrant)
	ANTHONY F. EARLEY, JR.		NICKOLAS STAVROPOULOS
	Anthony F. Earley, Jr.		Nickolas Stavropoulos
By:	Chairman of the Board, Chief Executive Officer, and President	By:	President, Gas
Date:	February 18, 2016	Date:	February 18, 2016
			GEISHA J. WILLIAMS
			Geisha J. Williams
		By:	President, Electric
		Date:	February 18, 2016

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
ANTHONY F. EARLEY, JR.	Chairman of the Board, Chief Executive Officer, and	February 18, 2016
Anthony F. Earley, Jr.	President (PG&E Corporation)
NICKOLAS STAVROPOULOS	President, Gas	February 18, 2016
Nickolas Stavropoulos	(Pacific Gas and Electric Company)
GEISHA J. WILLIAMS	President, Electric	February 18, 2016
Geisha J. Williams	(Pacific Gas and Electric Company)
B.Principal Financial Officers
JASON P. WELLS	Senior Vice President and Chief Financial Officer	February 18, 2016
Jason P. Wells	(PG&E Corporation)
DINYAR B. MISTRY	Vice President, Chief Financial Officer, and	February 18, 2016
Dinyar B. Mistry	Controller(Pacific Gas and Electric Company)

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C. Principal Accounting Officer
DINYAR B. MISTRY	Vice President and Controller (PG&E Corporation)	February 18, 2016
Dinyar B. Mistry	Vice President, Chief Financial Officer, and
	Controller(Pacific Gas and Electric Company)

147

	D.Directors
*	LEWIS CHEW	Director	February 18, 2016
	Lewis Chew
*	ANTHONY F. EARLEY, JR.	Director	February 18, 2016
	Anthony F. Earley, Jr.
*	FRED J. FOWLER	Director	February 18, 2016
	Fred J. Fowler
*	MARYELLEN C. HERRINGER	Director	February 18, 2016
	Maryellen C. Herringer
*	RICHARD C. KELLY	Director	February 18, 2016
	Richard C. Kelly
*	ROGER H. KIMMEL	Director	February 18, 2016
	Roger H. Kimmel
*	RICHARD A. MESERVE	Director	February 18, 2016
	Richard A. Meserve
*	FORREST E. MILLER	Director	February 18, 2016
	Forrest E. Miller
*	ROSENDO G. PARRA	Director	February 18, 2016
	Rosendo G. Parra
*	BARBARA L. RAMBO	Director	February 18, 2016
	Barbara L. Rambo
*	ANNE SHEN SMITH	Director	February 18, 2016
	Anne Shen Smith
*	NICKOLAS STAVROPOULOS	Director (Pacific Gas and Electric Company only)	February 18, 2016
	Nickolas Stavropoulos
*	GEISHA J. WILLIAMS	Director (Pacific Gas and Electric Company only)	February 18, 2016
	Geisha J. Williams
*	BARRY LAWSON WILLIAMS	Director	February 18, 2016
	Barry Lawson Williams
*By:	HYUN PARK
	HYUN PARK, Attorney-in-Fact

148

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, 2015 and 2014, and for each of the three years in the period ended December 31, 2015, and the Company's and the Utility’s internal control over financial reporting as of December 31, 2015, and have issued our reports thereon dated February 18, 2016; such reports are included in this Form 10-K.Our audits also included the consolidated financial statement schedules of the Company and the 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 18, 2016

149

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

		Years Ended December 31,
(in millions, except per share amounts)		2015		2014		2013
Administrative service revenue	$	51	$	51	$	41
Operating expenses		(53)		(53)		(42)
Interest income		1		1		1
Interest expense		(10)		(14)		(25)
Other income (expense)		30		(1)		(57)
Equity in earnings of subsidiaries		852		1,413		848
Income before income taxes		871		1,397		766
Income tax benefit		3		39		48
Net income	$	874	$	1,436	$	814
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $0,
$10, and $80, at respective dates)	$	(1)	$	(14)	$	113
Net change in investments (net of taxes of $12, $17, and $26, at respective dates)		(17)		(25)		38
Total other comprehensive income (loss)		(18)		(39)		151
Comprehensive Income	$	856	$	1,397	$	965
Weighted Average Common Shares Outstanding, Basic		484		468		444
Weighted Average Common Shares Outstanding, Diluted		487		470		445
Net earnings per common share, basic	$	1.81	$	3.07	$	1.83
Net earnings per common share, diluted	$	1.79	$	3.06	$	1.83

150

PG&E CORPORATION

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

CONDENSED BALANCE SHEETS

	Balance at December31,
(in millions)	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	64	$	96
Advances to affiliates		22		31
Income taxes receivable		24		29
Other		1		38
Total current assets		111		194
Noncurrent Assets
Equipment		2		2
Accumulated depreciation		(2)		(1)
Net equipment		-		1
Investments in subsidiaries		16,837		16,003
Other investments		130		117
Deferred income taxes		250		260
Total noncurrent assets		17,217		16,381
Total Assets	$	17,328	$	16,575
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable – other		3		67
Other		246		269
Total current liabilities		249		336
Noncurrent Liabilities
Long-term debt		350		350
Other		153		141
Total noncurrent liabilities		503		491
Common Shareholders’ Equity
Common stock		11,282		10,421
Reinvested earnings		5,301		5,316
Accumulated other comprehensive income (loss)		(7)		11
Total common shareholders’ equity		16,576		15,748
Total Liabilities and Shareholders’ Equity	$	17,328	$	16,575

151

PG&E CORPORATION

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

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2015		2014		2013
Cash Flows from Operating Activities:
Net income	$	874	$	1,436	$	814
Adjustments to reconcile net income to net cash provided by
operating activities:
Stock-based compensation amortization		66		65		54
Equity in earnings of subsidiaries		(852)		(1,413)		(848)
Deferred income taxes and tax credits-net		10		(72)		(10)
Noncurrent income taxes receivable/payable		-		5		-
Current income taxes receivable/payable		5		(16)		20
Other		(70)		43		(20)
Net cash provided by operating activities		33		48		10
Cash Flows From Investing Activities:
Investment in subsidiaries		(705)		(978)		(1,371)
Dividends received from subsidiaries (1)		716		716		716
Proceeds from tax equity investments		-		368		275
Other		-		-		(8)
Net cash provided by (used in) investing activities		11		106		(388)
Cash Flows From Financing Activities:
Borrowings (repayments) under revolving credit facilities		-		(260)		140
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $3 million		-		347		-
Repayments of long-term debt		-		(350)		-
Common stock issued		780		802		1,045
Common stock dividends paid(2)		(856)		(828)		(782)
Other		-		-		(1)
Net cash provided by (used in) financing activities		(76)		(289)		402
Net change in cash and cash equivalents		(32)		(135)		24
Cash and cash equivalents at January 1		96		231		207
Cash and cash equivalents at December 31	$	64	$	96	$	231
Supplemental disclosure of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(9)	$	(15)	$	(23)
Income taxes, net		-		1		21
Supplemental disclosure of noncash investing and financing activities
Noncash common stock issuances	$	21	$	21	$	22
Common stock dividends declared but not yet paid		224		217		208

(1)Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow.

(2)In January, April, July, and October of 2015, 2014, and 2013, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

152

PG&E Corporation

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2015, 2014, and 2013

(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:
2015:
Allowance for uncollectible accounts (1)	$	66	$	43	$	-	$	55	$	54
2014:
Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66
2013:
Allowance for uncollectible accounts (1)	$	87	$	53	$	-	$	60	$	80

(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.

153

Pacific Gas and Electric Company

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2015, 2014, and 2013

(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:
2015:
Allowance for uncollectible accounts (1)	$	66	$	43	$	-	$	55	$	54
2014:
Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66
2013:
Allowance for uncollectible accounts (1)	$	87	$	53	$	-	$	60	$	80

(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.

154

EXHIBIT INDEX

Exhibit Number	Exhibit Description
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 February 19, 2014 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 3.1)
3.4	Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April12, 2004 (File No.1-2348), Exhibit 3)
3.5	Bylaws of Pacific Gas and Electric Company amended as of August 17, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on July 14, 2015 (File No. 1-2348), Exhibit 99.2)
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), Exhibit4.1)
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 December4, 2007 relating to the Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes due November30, 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 November18, 2008 relating to the Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25% Senior Notes due December1, 2013 and $200million principal amount of its 8.25% Senior Notes due October15, 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 March6, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March1, 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 November18, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January15, 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)

155

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 January15, 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 May15, 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	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)
4.15	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)
4.16	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)
4.17	Nineteenth Supplemental Indenture dated as of June 14, 2013 relating to the issuance of $375,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due June 15, 2023 and $375,000,000 aggregate principal amount of its 4.60% Senior Notes due June 15, 2043(incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 14, 2013 (File No. 1-2348), Exhibit 4.1)
4.18	Twentieth Supplemental Indenture dated as of November 12, 2013 relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.85% Senior Notes due November 15, 2023 and $500,000,000 aggregate principal amount of its 5.125% Senior Notes due November 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2013 (File No. 1-2348), Exhibit 4.1)
4.19	Twenty-First Supplemental Indenture, dated as of February 21, 2014, relating to the issuance of $450,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due February 15, 2024 and $450,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 21, 2014 (File No.12348), Exhibit 4.1)

156

4.20	Twenty-Third Supplemental Indenture, dated as of August 18, 2014, relating to the issuance of $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.40% Senior Notes due August 15, 2024 and $225,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 18, 2014 (File No. 1-2348), Exhibit 4.1)
4.21	Twenty-Fourth Supplemental Indenture, dated as of November 6, 2014, relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 6, 2014 (File No. 1-2348), Exhibit 4.1)
4.22	Twenty-Fifth Supplemental Indenture, dated as of June 12, 2015, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 and $100,000,000 aggregate principal amount of its 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on June 12, 2015 (File No. 1-2348), Exhibit 4.1)
4.23	Twenty-Sixth Supplemental Indenture, dated as of November 5, 2015, relating to the issuance of $200,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 and $450,000,000 aggregate principal amount of its 4.25% Senior Notes due March 15, 2046 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on November 5, 2015 (File No. 1-2348), Exhibit 4.1)
4.24	Senior Note Indenture, dated as of February 10, 2014, between PG&E Corporation and U.S. Bank National Association (incorporated by reference to PG&E Corporation’s Form S-3 (File No. 333-193880), Exhibit 4.1)
4.25	First Supplemental Indenture, dated as of February 27, 2014, relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 2.40% Senior Notes due March 1, 2019 (incorporated by reference to PG&E Corporation’s Form 8-K dated February 27, 2014 (File No. 1-12609), Exhibit 4.1)
10.1	Second Amended and Restated Credit Agreement dated as of April 27, 2015, among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and Wells Fargo Securities LLC, as joint lead arrangers and joint bookrunners, (4) Citibank N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association, as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank, National Association, MUFG Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.1)
10.2	Second Amended and Restated Credit Agreement dated as of April 27, 2015, among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and Wells Fargo Securities LLC, as joint lead arrangers and joint bookrunners, (4) Bank of America, N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association, as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, MUFG Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-2348), Exhibit 10.2)
10.3	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)

157

10.4		Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March31, 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)
10.5	*	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)
10.6	*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015(File No. 1-12609), Exhibit 10.7)
10.7	*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2014 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, 2014(File No. 1-12609), Exhibit 10.4)
10.8	*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 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, 2013 (File No. 1-12609), Exhibit 10.5)
10.9	*	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)
10.10	*	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)
10.11	*	Performance Share Agreement subject to financial goals between Anthony F. Earley, Jr. and PG&E Corporation for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015(File No. 1-12609), Exhibit 10.8)
10.12	*	Performance Share Agreement subject to safety and customer affordability goals between Anthony F. Earley, Jr. and PG&E Corporation for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015(File No. 1-12609), Exhibit 10.9)
10.13	*	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2014 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, 2014(File No. 1-12609), Exhibit 10.5)
10.14	*	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 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, 2013 (File No. 1-12609), Exhibit 10.6)
10.15	*	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)
10.16	*	Restricted Stock Unit Agreement between Nickolas Stavropoulos and PG&E Corporation for additional 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan
10.17	*	Restricted Stock Unit Agreement between Geisha J. Williams and PG&E Corporation for additional 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan
10.18	*	Restricted Stock Unit Agreement between John R. Simon and PG&E Corporation for additional 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan

158

10.19	*	Letter regarding Compensation Agreement between PG&E Corporation and Julie M. Kane dated March 11, 2015 for employment starting May 18, 2015 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 (File No. 1-2348), Exhibit 10.4)
10.20	*	Restricted Stock Unit Agreement between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 (File No. 1-2348), Exhibit 10.5)
10.21	*	Non-Annual Restricted Stock Unit Agreement between Julie M. Kane and PG&E Corporation dated May 29, 2015 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 (File No. 1-2348), Exhibit 10.6)
10.22	*	Performance Share Agreement subject to financial goals between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 (File No. 1-2348), Exhibit 10.7)
10.23	*	Performance Share Agreement subject to safety and customer affordability goals between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 (File No. 1-2348), Exhibit 10.8)
10.24	*	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)
10.25	*	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)
10.26	*	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)
10.27	*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Nickolas 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)
10.28	*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Steven Malnight dated February 22, 2012(incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2014 (File No. 1-2348), Exhibit 10.3)
10.29	*	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)
10.30	*	PG&E Corporation 2005 Supplemental Retirement Savings Plan, as amended effective September 15, 2015 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2015 (File No.1-12609), Exhibit10.3)
10.31	*	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), Exhibit10.24)
10.32	*	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)
10.33	*	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2015(incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.3)

159

10.34	*	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), Exhibit10.27)
10.35	*	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), Exhibit10.28)
10.36	*	PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of January 1, 2013 (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)
10.37	*	PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective September 17, 2013 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2013 (File No.1-12609), Exhibit10.2)
10.38	*	Pacific Gas and Electric Company Relocation Assistance Program for Officers
10.39	*	Amendment to the Postretirement Life Insurance Plan of the Pacific Gas and Electric Company, effective February 6, 2015(incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2014) (File No. 1-12609), Exhibit 10.37)
10.40	*	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), Exhibit10.7)
10.41	*	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)
10.42	*	PG&E Corporation 2014 Long-Term Incentive Plan effective May 12, 2014 and amended effective January 1, 2016
10.43	*	PG&E Corporation 2006 Long-Term Incentive Plan, as amended effective January 1, 2013 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2012(File No.1-12609), Exhibit10.40)
10.44	*	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), Exhibit10)
10.45	*	Form of Restricted Stock Unit Agreement for 2015 grants to directors under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2015 (File No. 1-12609), Exhibit 10.3)
10.46	*	Form of Restricted Stock Unit Agreement for 2015 grants under the PG&E Corporation 2014 Long-Term Incentive Plan(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.4)
10.47	*	Form of Restricted Stock Unit Agreement for 2014 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, 2014 (File No.1-12609), Exhibit10.2)
10.48	*	Form of Restricted Stock Unit Agreement for 2013 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, 2013 (File No.1-12609), Exhibit10.3)
10.49	*	Form of Restricted Stock Unit 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), Exhibit10.1)
10.50	*	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), Exhibit10.1)

160

10.51	*	Form of Restricted Stock Unit Agreement for 2014 grants to directors under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2014 (File No.1-12609), Exhibit10.3)
10.52	*	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 January6, 2005 (File No.1-12609 and File No.1-2348), Exhibit99.1)
10.53	*	Form of Performance Share Agreement subject to financial goals for 2015 grants under the PG&E Corporation 2014 Long-Term Incentive Plan(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.5)
10.54	*	Form of Performance Share Agreement subject to safety and customer affordability goals for 2015 grants under the PG&E Corporation 2014 Long-Term Incentive Plan(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.6)
10.55	*	Form of Performance Share Agreement for 2014 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, 2014(File No.1-12609), Exhibit10.3)
10.56	*	Form of Performance Share Agreement for 2013 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, 2013 (File No.1-12609), Exhibit10.4)
10.57	*	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), Exhibit10.2)
10.58	*	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), Exhibit10.3)
10.59	*	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), Exhibit10.2)
10.60	*	PG&E Corporation 2012 Officer Severance Policy, as amended effective as of May 12, 2014 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2014 (File No.1-12609), Exhibit10.2)
10.61	*	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), Exhibit10.5)
10.62	*	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), Exhibit10.49)
10.63	*	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), Exhibit10.58)
10.64	*	Amended and Restated PG&E Corporation Director Grantor Trust Agreement dated October 1, 2015 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2015 (File No. 1-12609), Exhibit 10.1)
10.65	*	Amended and Restated PG&E Corporation Officer Grantor Trust Agreement dated October 1, 2015 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2015 (File No. 1-12609), Exhibit 10.2)
10.66	*	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), Exhibit10.54)
10.67	*	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), Exhibit10.40)

161

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

162

EX-10.16

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

NON-ANNUAL RESTRICTED STOCK UNIT GRANT

PG&E CORPORATION, a California corporation, hereby grants Restricted Stock Units to the Recipient named below.  The Restricted Stock Units have been granted under the PG&E Corporation 2014 Long-Term Incentive Plan, as amended (the "LTIP").  The terms and conditions of the Restricted Stock Units are set forth in this cover sheet and in the attached Restricted Stock Unit Agreement (the "Agreement").

Date of Grant:August 17, 2015

Name of Recipient:Nickolas Stavropoulos

Recipient's Participant ID:XXXXXXXX

Number of Restricted Stock Units:9,214

By accepting this award, you agree to all of the terms and conditions described in the attached Agreement. You and PG&E Corporation agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of the attached Agreement.  You are also acknowledging receipt of this Grant, the attached Agreement, and a copy of the prospectus describing the LTIP and the Restricted Stock Units dated May 12, 2014.

If, for any reason, you wish to not accept this award, please notify PG&E Corporation in writing within 30 calendar days of the date of this award at ATTN: LTIP Administrator at Pacific Gas and Electric Company, 245 Market Street, N2T, San Francisco, 94105.

Attachment

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT AGREEMENT

The LTIP and Other Agreements	This Agreement constitutes the entire understanding between you and PG&E Corporation regarding the Restricted Stock Units, subject to the terms of the LTIP.  Any prior agreements, commitments, or negotiations are superseded.  In the event of any conflict or inconsistency between the provisions of this Agreement and the LTIP, the LTIP shall govern.  Capitalized terms that are not defined in this Agreement are defined in the LTIP.  In the event of any conflict between the provisions of this Agreement and the PG&E Corporation Officer Severance Policy or the PG&E Corporation 2012 Officer Severance Policy, this Agreement shall govern. For purposes of this Agreement, employment with PG&E Corporation shall mean employment with any member of the Participating Company Group.
Grant of Restricted Stock Units	PG&E Corporation grants you the number of Restricted Stock Units shown on the cover sheet of this Agreement.  The Restricted Stock Units are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Restricted Stock Units	As long as you remain employed with PG&E Corporation, the total number of Restricted Stock Units originally subject to this Agreement, as shown above on the cover sheet, will vest in accordance with the below vesting schedule ([collectively], the "Normal Vesting Schedule") 4,607 on August 17, 2017 4,607 on August 17, 2018 The amounts payable upon each vesting date are hereby designated separate payments for purposes of Code Section 409A.  Except as described below, all Restricted Stock Units subject to this Agreement which have not vested upon termination of your employment shall then be automatically cancelled. As set forth below, the Restricted Stock Units may vest earlier upon the occurrence of certain events.
Dividends	Restricted Stock Units will accrue Dividend Equivalents in the event cash dividends are paid with respect to PG&E Corporation common stock having a record date prior to the date on which the Restricted Stock Units are settled.  Such Dividend Equivalents will be converted into cash and paid, if at all, upon settlement of the underlying Restricted Stock Units.
Settlement	Vested Restricted Stock Units will be settled in an equal number of shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below.  PG&E Corporation shall issue shares as soon as practicable after the Restricted Stock Units vest in accordance with the Normal Vesting Schedule (but not later than sixty (60) days after the applicable vesting date); provided, however, that such issuance shall, if earlier, be made with respect to all of your outstanding vested Restricted Stock Units (after giving effect to the vesting provisions described below) as soon as practicable after (but not later than sixty (60) days after) the earliest to occur of your (1) Disability (as defined under Code Section 409A), (2) death or (3) "separation from service," within the meaning of Code Section 409A within 2 years following a Change in Control.
Voluntary Termination	In the event of your voluntary termination, all unvested Restricted Stock Units will be cancelled on the date of termination.
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause, all unvested Restricted Stock Units will be cancelled on the date of termination.  In general, termination for "cause" means termination of employment because of dishonesty, a criminal offense or violation of a work rule, and will be determined by and in the sole discretion of PG&E Corporation.
Termination other than for Cause	If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause and you are an officer in Bands 1-5, any unvested Restricted Stock Units that would have vested during the period of the "Severance Multiple" under the PG&E Corporation Officer Severance Policy or the PG&E Corporation 2012 Officer Severance Policy (as applicable at the time of termination) will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement.  In the event of your involuntary termination other than for cause, if you are not an officer in Bands 1-5, any unvested Restricted Stock Units that would have vested within the 12 months following such termination had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement.  All other unvested Restricted Stock Units will be cancelled unless your termination of employment was in connection with a Change in Control as provided below.
Death/Disability	In the event of your death or Disability while you are employed, all of your Restricted Stock Units shall vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such event.  If your death or Disability occurs following the termination of your employment and your Restricted Stock Units are then outstanding under the terms hereof, then all of your vested Restricted Stock Units plus any Restricted Stock Units that would have otherwise vested during any continued vesting period hereunder shall be settled as soon as practicable after (but not later than sixty (60) days after) the date of your death or Disability.
Termination Due to Disposition of Subsidiary	(1) If your employment is terminated (other than termination for cause, your voluntary termination) by reason of a divestiture or change in control of a subsidiary of PG&E Corporation, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Section 424(f) of the Internal Revenue Code of 1986, as amended (the "Code"), or (2) if your employment is terminated (other than termination for cause, or your voluntary termination) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, the Restricted Stock Units shall vest and be settled in the same manner as for a "Termination other than for Cause" described above.
Change in Control	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 your consent, either assume or continue PG&E Corporation's rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Restricted Stock Units subject to this Agreement. If the Restricted Stock Units are neither assumed nor continued by the Acquiror or if the Acquiror does not provide a substantially equivalent award in substitution for the Restricted Stock Units, all of your unvested Restricted Stock Units shall automatically vest immediately preceding and contingent on, the Change in Control and be settled in accordance with the Normal Vesting Schedule, subject to the earlier settlement provisions of this Agreement.
Termination In Connection with a Change in Control	If you separate from service (other than termination for cause, your voluntary termination) in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Restricted Stock Units (including Restricted Stock Units that you would have otherwise forfeited after the end of the continued vesting period) shall automatically vest on the date of the Change in Control and will be settled in accordance with the Normal Vesting Schedule (without regard to the requirement that you be employed) subject to the earlier settlement provisions of this Agreement.  In the event of such a separation in connection with a Change in Control within two years following the Change in Control, your Restricted Stock Units (to the extent they did not previously vest upon, for example, failure of the Acquiror to assume or continue this Award) shall automatically vest on the date of such separation and will be settled as soon as practicable after (but not later than sixty (60) days after) the date of such separation.  PG&E Corporation shall have the sole discretion to determine whether termination of your employment was made in connection with a Change in Control
Delay	PG&E Corporation shall delay the issuance of any shares of common stock to the extent it is necessary to comply with Section 409A(a)(2)(B)(i) of the Code (relating to payments made to certain "key employees" of certain publicly-traded companies); in such event, any shares of common stock to which you would otherwise be entitled during the six (6) month period following the date of your "separation from service" under Section 409A (or shorter period ending on the date of your death following such separation) will instead be issued on the first business day following the expiration of the applicable delay period.
Withholding Taxes	The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of Restricted Stock Units will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Restricted Stock Units determined using the applicable minimum statutory withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax ("Withholding Taxes").  If the withheld shares were not sufficient to satisfy your minimum Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above.
Leaves of Absence	For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed.  If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment.  See above under "Voluntary Termination." Notwithstanding the foregoing, if the leave of absence exceeds six (6) months, and a return to service upon expiration of such leave is not guaranteed by statute or contract, then you shall be deemed to have had a "separation from service" for purposes of any Restricted Stock Units that are settled hereunder upon such separation.  To the extent an authorized leave of absence is due to a medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of at least six (6) months and such impairment causes you to be unable to perform the duties of your position of employment or any substantially similar position of employment, the six (6) month period in the prior sentence shall be twenty-nine (29) months. PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement.
Voting and Other Rights	You shall not have voting rights with respect to the Restricted Stock Units until the date the underlying shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent).
No Retention Rights	This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation.  Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right to terminate your employment at any time and for any reason.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

EX-10.17

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

NON-ANNUAL RESTRICTED STOCK UNIT GRANT

PG&E CORPORATION, a California corporation, hereby grants Restricted Stock Units to the Recipient named below.  The Restricted Stock Units have been granted under the PG&E Corporation 2014 Long-Term Incentive Plan, as amended (the "LTIP").  The terms and conditions of the Restricted Stock Units are set forth in this cover sheet and in the attached Restricted Stock Unit Agreement (the "Agreement").

Date of Grant:August 17, 2015

Name of Recipient:Geisha Williams

Recipient's Participant ID:XXXXXXXX

Number of Restricted Stock Units:9,214

By accepting this award, you agree to all of the terms and conditions described in the attached Agreement. You and PG&E Corporation agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of the attached Agreement.  You are also acknowledging receipt of this Grant, the attached Agreement, and a copy of the prospectus describing the LTIP and the Restricted Stock Units dated May 12, 2014.

If, for any reason, you wish to not accept this award, please notify PG&E Corporation in writing within 30 calendar days of the date of this award at ATTN: LTIP Administrator at Pacific Gas and Electric Company, 245 Market Street, N2T, San Francisco, 94105.

Attachment

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT AGREEMENT

The LTIP and Other Agreements	This Agreement constitutes the entire understanding between you and PG&E Corporation regarding the Restricted Stock Units, subject to the terms of the LTIP.  Any prior agreements, commitments, or negotiations are superseded.  In the event of any conflict or inconsistency between the provisions of this Agreement and the LTIP, the LTIP shall govern.  Capitalized terms that are not defined in this Agreement are defined in the LTIP.  In the event of any conflict between the provisions of this Agreement and the PG&E Corporation Officer Severance Policy or the PG&E Corporation 2012 Officer Severance Policy, this Agreement shall govern. For purposes of this Agreement, employment with PG&E Corporation shall mean employment with any member of the Participating Company Group.
Grant of Restricted Stock Units	PG&E Corporation grants you the number of Restricted Stock Units shown on the cover sheet of this Agreement.  The Restricted Stock Units are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Restricted Stock Units	As long as you remain employed with PG&E Corporation, the total number of Restricted Stock Units originally subject to this Agreement, as shown above on the cover sheet, will vest in accordance with the below vesting schedule ([collectively], the "Normal Vesting Schedule") 4,607 on August 17, 2017 4,607 on August 17, 2018 The amounts payable upon each vesting date are hereby designated separate payments for purposes of Code Section 409A.  Except as described below, all Restricted Stock Units subject to this Agreement which have not vested upon termination of your employment shall then be automatically cancelled. As set forth below, the Restricted Stock Units may vest earlier upon the occurrence of certain events.
Dividends	Restricted Stock Units will accrue Dividend Equivalents in the event cash dividends are paid with respect to PG&E Corporation common stock having a record date prior to the date on which the Restricted Stock Units are settled.  Such Dividend Equivalents will be converted into cash and paid, if at all, upon settlement of the underlying Restricted Stock Units.
Settlement	Vested Restricted Stock Units will be settled in an equal number of shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below.  PG&E Corporation shall issue shares as soon as practicable after the Restricted Stock Units vest in accordance with the Normal Vesting Schedule (but not later than sixty (60) days after the applicable vesting date); provided, however, that such issuance shall, if earlier, be made with respect to all of your outstanding vested Restricted Stock Units (after giving effect to the vesting provisions described below) as soon as practicable after (but not later than sixty (60) days after) the earliest to occur of your (1) Disability (as defined under Code Section 409A), (2) death or (3) "separation from service," within the meaning of Code Section 409A within 2 years following a Change in Control.
Voluntary Termination	In the event of your voluntary termination, all unvested Restricted Stock Units will be cancelled on the date of termination.
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause, all unvested Restricted Stock Units will be cancelled on the date of termination.  In general, termination for "cause" means termination of employment because of dishonesty, a criminal offense or violation of a work rule, and will be determined by and in the sole discretion of PG&E Corporation.
Termination other than for Cause	If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause and you are an officer in Bands 1-5, any unvested Restricted Stock Units that would have vested during the period of the "Severance Multiple" under the PG&E Corporation Officer Severance Policy or the PG&E Corporation 2012 Officer Severance Policy (as applicable at the time of termination) will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement.  In the event of your involuntary termination other than for cause, if you are not an officer in Bands 1-5, any unvested Restricted Stock Units that would have vested within the 12 months following such termination had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement.  All other unvested Restricted Stock Units will be cancelled unless your termination of employment was in connection with a Change in Control as provided below.
Death/Disability	In the event of your death or Disability while you are employed, all of your Restricted Stock Units shall vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such event.  If your death or Disability occurs following the termination of your employment and your Restricted Stock Units are then outstanding under the terms hereof, then all of your vested Restricted Stock Units plus any Restricted Stock Units that would have otherwise vested during any continued vesting period hereunder shall be settled as soon as practicable after (but not later than sixty (60) days after) the date of your death or Disability.
Termination Due to Disposition of Subsidiary	(1) If your employment is terminated (other than termination for cause, your voluntary termination) by reason of a divestiture or change in control of a subsidiary of PG&E Corporation, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Section 424(f) of the Internal Revenue Code of 1986, as amended (the "Code"), or (2) if your employment is terminated (other than termination for cause, or your voluntary termination) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, the Restricted Stock Units shall vest and be settled in the same manner as for a "Termination other than for Cause" described above.
Change in Control	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 your consent, either assume or continue PG&E Corporation's rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Restricted Stock Units subject to this Agreement. If the Restricted Stock Units are neither assumed nor continued by the Acquiror or if the Acquiror does not provide a substantially equivalent award in substitution for the Restricted Stock Units, all of your unvested Restricted Stock Units shall automatically vest immediately preceding and contingent on, the Change in Control and be settled in accordance with the Normal Vesting Schedule, subject to the earlier settlement provisions of this Agreement.
Termination In Connection with a Change in Control	If you separate from service (other than termination for cause, your voluntary termination) in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Restricted Stock Units (including Restricted Stock Units that you would have otherwise forfeited after the end of the continued vesting period) shall automatically vest on the date of the Change in Control and will be settled in accordance with the Normal Vesting Schedule (without regard to the requirement that you be employed) subject to the earlier settlement provisions of this Agreement.  In the event of such a separation in connection with a Change in Control within two years following the Change in Control, your Restricted Stock Units (to the extent they did not previously vest upon, for example, failure of the Acquiror to assume or continue this Award) shall automatically vest on the date of such separation and will be settled as soon as practicable after (but not later than sixty (60) days after) the date of such separation.  PG&E Corporation shall have the sole discretion to determine whether termination of your employment was made in connection with a Change in Control
Delay	PG&E Corporation shall delay the issuance of any shares of common stock to the extent it is necessary to comply with Section 409A(a)(2)(B)(i) of the Code (relating to payments made to certain "key employees" of certain publicly-traded companies); in such event, any shares of common stock to which you would otherwise be entitled during the six (6) month period following the date of your "separation from service" under Section 409A (or shorter period ending on the date of your death following such separation) will instead be issued on the first business day following the expiration of the applicable delay period.
Withholding Taxes	The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of Restricted Stock Units will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Restricted Stock Units determined using the applicable minimum statutory withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax ("Withholding Taxes").  If the withheld shares were not sufficient to satisfy your minimum Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above.
Leaves of Absence	For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed.  If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment.  See above under "Voluntary Termination." Notwithstanding the foregoing, if the leave of absence exceeds six (6) months, and a return to service upon expiration of such leave is not guaranteed by statute or contract, then you shall be deemed to have had a "separation from service" for purposes of any Restricted Stock Units that are settled hereunder upon such separation.  To the extent an authorized leave of absence is due to a medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of at least six (6) months and such impairment causes you to be unable to perform the duties of your position of employment or any substantially similar position of employment, the six (6) month period in the prior sentence shall be twenty-nine (29) months. PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement.
Voting and Other Rights	You shall not have voting rights with respect to the Restricted Stock Units until the date the underlying shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent).
No Retention Rights	This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation.  Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right to terminate your employment at any time and for any reason.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

EX-10.18

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

NON-ANNUAL RESTRICTED STOCK UNIT GRANT

PG&E CORPORATION, a California corporation, hereby grants Restricted Stock Units to the Recipient named below.  The Restricted Stock Units have been granted under the PG&E Corporation 2014 Long-Term Incentive Plan, as amended (the "LTIP").  The terms and conditions of the Restricted Stock Units are set forth in this cover sheet and in the attached Restricted Stock Unit Agreement (the "Agreement").

Date of Grant:August 17, 2015

Name of Recipient:John Simon

Recipient's Participant ID:XXXXXXXX

Number of Restricted Stock Units:7,371

By accepting this award, you agree to all of the terms and conditions described in the attached Agreement. You and PG&E Corporation agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of the attached Agreement.  You are also acknowledging receipt of this Grant, the attached Agreement, and a copy of the prospectus describing the LTIP and the Restricted Stock Units dated May 12, 2014.

If, for any reason, you wish to not accept this award, please notify PG&E Corporation in writing within 30 calendar days of the date of this award at ATTN: LTIP Administrator at Pacific Gas and Electric Company, 245 Market Street, N2T, San Francisco, 94105.

Attachment

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT AGREEMENT

The LTIP and Other Agreements	This Agreement constitutes the entire understanding between you and PG&E Corporation regarding the Restricted Stock Units, subject to the terms of the LTIP.  Any prior agreements, commitments, or negotiations are superseded.  In the event of any conflict or inconsistency between the provisions of this Agreement and the LTIP, the LTIP shall govern.  Capitalized terms that are not defined in this Agreement are defined in the LTIP.  In the event of any conflict between the provisions of this Agreement and the PG&E Corporation Officer Severance Policy or the PG&E Corporation 2012 Officer Severance Policy, this Agreement shall govern. For purposes of this Agreement, employment with PG&E Corporation shall mean employment with any member of the Participating Company Group.
Grant of Restricted Stock Units	PG&E Corporation grants you the number of Restricted Stock Units shown on the cover sheet of this Agreement.  The Restricted Stock Units are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Restricted Stock Units	As long as you remain employed with PG&E Corporation, the total number of Restricted Stock Units originally subject to this Agreement, as shown above on the cover sheet, will vest in accordance with the below vesting schedule ([collectively], the "Normal Vesting Schedule") 3,685 on August 17, 2017 3,686 on August 17, 2018 The amounts payable upon each vesting date are hereby designated separate payments for purposes of Code Section 409A.  Except as described below, all Restricted Stock Units subject to this Agreement which have not vested upon termination of your employment shall then be automatically cancelled. As set forth below, the Restricted Stock Units may vest earlier upon the occurrence of certain events.
Dividends	Restricted Stock Units will accrue Dividend Equivalents in the event cash dividends are paid with respect to PG&E Corporation common stock having a record date prior to the date on which the Restricted Stock Units are settled.  Such Dividend Equivalents will be converted into cash and paid, if at all, upon settlement of the underlying Restricted Stock Units.
Settlement	Vested Restricted Stock Units will be settled in an equal number of shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below.  PG&E Corporation shall issue shares as soon as practicable after the Restricted Stock Units vest in accordance with the Normal Vesting Schedule (but not later than sixty (60) days after the applicable vesting date); provided, however, that such issuance shall, if earlier, be made with respect to all of your outstanding vested Restricted Stock Units (after giving effect to the vesting provisions described below) as soon as practicable after (but not later than sixty (60) days after) the earliest to occur of your (1) Disability (as defined under Code Section 409A), (2) death or (3) "separation from service," within the meaning of Code Section 409A within 2 years following a Change in Control.
Voluntary Termination	In the event of your voluntary termination [(other than Retirement)], all unvested Restricted Stock Units will be cancelled on the date of termination.
[Retirement	In the event of your Retirement, unvested Restricted Stock Units will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement; provided, however that in the event of your Retirement within 2 years following a Change in Control, all of your Restricted Stock Units shall vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such event.  Your voluntary termination of employment will be considered to be a Retirement if you are both age 55 or older on the date of termination and if you were employed by PG&E Corporation for at least five consecutive years ending on the date of termination of your employment.]
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause, all unvested Restricted Stock Units will be cancelled on the date of termination.  In general, termination for "cause" means termination of employment because of dishonesty, a criminal offense or violation of a work rule, and will be determined by and in the sole discretion of PG&E Corporation.
Termination other than for Cause	If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause and you are an officer in Bands 1-5, any unvested Restricted Stock Units that would have vested during the period of the "Severance Multiple" under the PG&E Corporation Officer Severance Policy or the PG&E Corporation 2012 Officer Severance Policy (as applicable at the time of termination) will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement.  In the event of your involuntary termination other than for cause, if you are not an officer in Bands 1-5, any unvested Restricted Stock Units that would have vested within the 12 months following such termination had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement.  All other unvested Restricted Stock Units will be cancelled unless your termination of employment was in connection with a Change in Control as provided below.
Death/Disability	In the event of your death or Disability while you are employed, all of your Restricted Stock Units shall vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such event.  If your death or Disability occurs following the termination of your employment and your Restricted Stock Units are then outstanding under the terms hereof, then all of your vested Restricted Stock Units plus any Restricted Stock Units that would have otherwise vested during any continued vesting period hereunder shall be settled as soon as practicable after (but not later than sixty (60) days after) the date of your death or Disability.
Termination Due to Disposition of Subsidiary	(1) If your employment is terminated (other than termination for cause, [or]  your voluntary termination[, or your Retirement]) by reason of a divestiture or change in control of a subsidiary of PG&E Corporation, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Section 424(f) of the Internal Revenue Code of 1986, as amended (the "Code"), or (2) if your employment is terminated (other than termination for cause, [or] your voluntary termination[, or your Retirement]) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, the Restricted Stock Units shall vest and be settled in the same manner as for a "Termination other than for Cause" described above.
Change in Control	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 your consent, either assume or continue PG&E Corporation's rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Restricted Stock Units subject to this Agreement. If the Restricted Stock Units are neither assumed nor continued by the Acquiror or if the Acquiror does not provide a substantially equivalent award in substitution for the Restricted Stock Units, all of your unvested Restricted Stock Units shall automatically vest immediately preceding and contingent on, the Change in Control and be settled in accordance with the Normal Vesting Schedule, subject to the earlier settlement provisions of this Agreement.
Termination In Connection with a Change in Control	If you separate from service (other than termination for cause, [or] your voluntary termination[, or your Retirement]) in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Restricted Stock Units (including Restricted Stock Units that you would have otherwise forfeited after the end of the continued vesting period) shall automatically vest on the date of the Change in Control and will be settled in accordance with the Normal Vesting Schedule (without regard to the requirement that you be employed) subject to the earlier settlement provisions of this Agreement.  In the event of such a separation in connection with a Change in Control within two years following the Change in Control, your Restricted Stock Units (to the extent they did not previously vest upon, for example, failure of the Acquiror to assume or continue this Award) shall automatically vest on the date of such separation and will be settled as soon as practicable after (but not later than sixty (60) days after) the date of such separation.  PG&E Corporation shall have the sole discretion to determine whether termination of your employment was made in connection with a Change in Control
Delay	PG&E Corporation shall delay the issuance of any shares of common stock to the extent it is necessary to comply with Section 409A(a)(2)(B)(i) of the Code (relating to payments made to certain "key employees" of certain publicly-traded companies); in such event, any shares of common stock to which you would otherwise be entitled during the six (6) month period following the date of your "separation from service" under Section 409A (or shorter period ending on the date of your death following such separation) will instead be issued on the first business day following the expiration of the applicable delay period.
Withholding Taxes	The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of Restricted Stock Units will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Restricted Stock Units determined using the applicable minimum statutory withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax ("Withholding Taxes").  If the withheld shares were not sufficient to satisfy your minimum Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above.
Leaves of Absence	For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed.  If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment.  See above under "Voluntary Termination." Notwithstanding the foregoing, if the leave of absence exceeds six (6) months, and a return to service upon expiration of such leave is not guaranteed by statute or contract, then you shall be deemed to have had a "separation from service" for purposes of any Restricted Stock Units that are settled hereunder upon such separation.  To the extent an authorized leave of absence is due to a medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of at least six (6) months and such impairment causes you to be unable to perform the duties of your position of employment or any substantially similar position of employment, the six (6) month period in the prior sentence shall be twenty-nine (29) months. PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement.
Voting and Other Rights	You shall not have voting rights with respect to the Restricted Stock Units until the date the underlying shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent).
No Retention Rights	This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation.  Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right to terminate your employment at any time and for any reason.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

EX-10.38

Officer Relocation Guide

Table of Contents

TABLE OF CONTENTS

GETTING STARTED

Your Relocation Guide

Important Notices

ALTAIR WILL ADMINISTER YOUR RELOCATION

RELOCATION SUMMARY

ELIGIBILITY FOR BENEFITS

RELOCATION REPAYMENT AGREEMENT

MISCELLANEOUS EXPENSE ALLOWANCE

LEASE CANCELLATION

Relocation Clause

HOME SALE ASSISTANCE PROGRAM

You Must Work with Altair

Eligibility of the Home

If your home is ineligible for the Home Sale Assistance Program

If your home is eligible for the Home Sale Assistance Program

Step 1:Speak with your RMC consultant before signing any agreement(s) with real estate professionals regarding the sale of your home.

Step 2:Broker's Market Analysis

Step 3:Selecting a broker or agent to sell your home

Step 4:Listing your home for sale

Step 5:Work closely with the broker and the RMC  to locate a buyer for your home.

Step 6:Review any purchase offers on the home with your RMC consultant.

Step 7:Amended Value Sale

Step 8:Closing an Amended Value Sale

Step 9:Cost of Ownership

Step 10:Vacating the Home

Tax Liability

GUARANTEED PURCHASE OFFER

Required Marketing Period

Relocation Appraisals determine the value of the Guaranteed Purchase Offer.

Accepting the Guaranteed Purchase Offer

Amended Value Sale

Home Sale Incentive

Possession Period

Proration Date

Pass-back of Gain or Loss on Sale to Employee

Tax Liability

EQUITY ADVANCE

Tax Liability

NEW HOME FINDING ASSISTANCE

Home Search Trip

Business Expenses

Tax Liability

LENDER REFERRAL

HOME PURCHASE CLOSING COSTS

Closing Procedures

Eligible Closing Expenses

Non-eligible Closing Expenses

Tax Liability

HOUSEHOLD GOODS MOVING

Insurance

Moving Services

Household Goods Storage

Transportation of Automobiles

Disconnecting and Connecting Appliances/Utilities

Special or Extraordinary Shipping Requirements Are Your Responsibility

Authorized Household Goods Eligible for Moving Benefit

Items NOT Authorized

Additional Exclusions

Important Information Concerning Household Goods Shipping

Tax Liability

TEMPORARY LIVING EXPENSES

Trips Home

Tax Liability

FINAL TRIP

Tax Liability

EXPENSE REPORTING

TAX LIABILITY ON RELOCATION EXPENSES PAID TO YOU OR ON YOUR BEHALF

RELOCATION REPAYMENT AGREEMENT

Getting Started

Your Relocation Guide

PG&E has established this relocation guide to assist in the financial and service needs of employees who meet the eligibility requirements and wish to relocate.  The guide is designed to address most events in a typical relocation and is intended to ease the transition to the new location for you and your family.

This guide outlines the various benefits available to you. We suggest that you review it carefully and make note of any questions you have or further information you may need.

Important Notices

§ PG&E reserves the right to interpret, at its sole discretion, the provisions of this program and to amend, limit or change any of its provisions with or without prior notice.

§ Nothing in this guide should be interpreted as an employment guarantee or as creating an employment contract, expressed or implied, for any duration.

§ The intent of the relocation program is to provide reasonable, consistent and cost effective financial assistance and quality services to employees who relocate. The guide does not offer or imply that all relocation costs will be fully compensated.

§ This relocation program has been designed to provide tax benefits and cost savings for you and PG&E. If you choose to work outside the guidelines, certain benefits may not be available to you.

§ It is expected that you will make every effort to transfer promptly and control the cost of your move whenever possible. You will be reimbursed for reasonable, necessary and properly authorized eligible expenses.  You are expected to maintain expenses at a conservative level and to be familiar with which expenses are reimbursable. The Company may, at its discretion, choose not to reimburse, in full or in part, an expense that is deemed unreasonable or excessive.

Altair Will Administer Your Relocation

Altair Global is a full-service Relocation Management Company (RMC) retained by PG&E to assist you with each step of your relocation. You will have one single point of contact, your RMC consultant, who will provide service, answer questions, and address any issues that arise.

In addition to normal business hours, your relocation consultant is available evenings and weekends to assist you with any aspect of your relocation.

Altair Global

201 N. Civic Drive, Suite 240

Walnut Creek, CA 94596

Toll Free: 800.934.5400

Direct: 925.945.1001

FAX: 925.945.1879

www.altairglobal.com

Altair's Employee and Family web site contains relocation resources, tools, and helpful information.  Once the RMC receives your authorization for relocation from PG&E, you will receive an invitation via email to create your account online. You will have access to:

§ Relocation policies and related documents

§ Online messages about your relocation

§ Submit and track expense reimbursement requests

Relocation Summary

Please Note: The following summary does not include all details regarding relocation benefits. Conditions and limitations may apply that need further explanation. Do not rely on this summary alone; read the entire document carefully and ask your RMC consultant to clarify any point that you do not understand.

PROVISION	OFFICER RELOCATION BENEFITS
Miscellaneous Expense Allowance	$7,000 (less applicable taxes).
Lease Cancellation	Necessary cancellation expenses up to two months' rent.
Home Sale Assistance	Includes professional home marketing assistance to support efforts to sell your home and implementation of a home sale assistance process that provides significant tax savings for both you and PG&E when an offer is received from an outside buyer.  You must call your RMC consultant before contacting a broker to list your home.
Guaranteed Purchase Offer (GPO)	The RMC prepares an offer for your home based on the average of two objective appraisals. The GPO may be accepted after your home has been marketed for 60 days.
Equity Advance	Equity advance up to 90% of equity based on the GPO.
New Home Finding Assistance	Maximum of two trips for a combined total of up to 8 days/7 nights for you and your spouse/registered domestic partner; eligible relocating children may go on one trip. Transportation (baggage fees not covered), lodging and meals (up to $75 per day per adults and children aged 16 and older, and $40 per day per child). Full day rental tour if seeking permanent rental accommodations.
Lender Referral	The RMC provides counseling and referral to lenders that offer special programs.
Home Purchase Closing Costs	Reimbursement will be equal to actual costs or 2.0% of the new home purchase price, whichever is less. You must call your RMC consultant before contacting a real estate agent to be eligible for closing cost reimbursement.
Household Goods Moving	Packing, loading, transportation, and insurance; 90 days in-transit storage for authorized household goods; up to 2 cars shipped if move is over 400 miles.
Temporary Living Expenses	Up to 6 months of corporate housing; a maximum of 2 round trips or mileage reimbursement for you to return to the departure location OR your spouse/registered domestic partner to visit the destination location. Up to 14 days of rental car while your personal auto is in transit.
Final Trip	Reasonable expenses for employee and eligible dependents. Meals (up to $75 per day per adult and children aged 16 and older and $40 per day per child) and lodging reimbursed with original receipts. One-way airfare and baggage fees for up to $100 in total per person if move is over 400 miles; or mileage reimbursed at the current IRS rate. One night's lodging and meals prior to departure, en route, and one night's expenses at destination.
Expense Reporting	Employee-paid eligible relocation expenses reimbursed by the RMC upon receiving completed expense form with itemized receipts for all expenses.
Tax Liability	Most taxable reimbursements are grossed up to compensate for the tax impact on the employee. Gross-up is provided as a financial benefit, but it is not intended to compensate you completely for all tax liabilities.

Eligibility for Benefits

To be eligible for Officer relocation benefits, you must meet the following requirements:

§ Your position is Vice President or higher.

§ You meet the following Internal Revenue Service (IRS) guidelines for a qualified move for tax purposes.

- The distance from your former residence to your new work location is 50 miles or greater than the distance from your former residence to your previous work location.

- You will be employed full time within the same general commuting area for 39 weeks or more within a 12-month period that begins when you arrive at the new location.

§ The relocation is between locations within the U.S. or from Canada to the U.S.

§ You complete the relocation benefits requirements within twelve (12) months from your hire date or internal transfer date.

§ You have signed and returned a relocation repayment agreement to the RMC.

Additionally, if you are a current employee transferring to another location, you must also meet the following requirements:

§ You must not have had a relocation paid for by the Company in the last twelve (12) months; and

§ The new position must be a regular, full-time position.

Relocation Repayment Agreement

To be eligible for relocation benefits, employees are required to sign and return a Relocation Repayment Agreement to the RMC. An employee who receives relocation assistance and voluntarily resigns employment within a 24-month period will be required to refund all or part of the monies spent by PG&E, including tax gross-up. Repayment will be as follows:

Resignation within the 1^st year: 100%

Resignation within the 2^nd year:  50%

If you are involuntarily terminated, you will not be responsible for repayment of any relocation expenses, regardless of the duration of employment at the new location.

No relocation benefits, including payments, will be made until a signed copy of the Relocation Repayment Agreement is on file.  A copy of the Agreement can be found at the end of this guide.

Miscellaneous Expense Allowance

PG&E's relocation program does not cover every expense you are likely to incur during your move. To help you with these various costs, PG&E provides a Miscellaneous Expense Allowance (MEA) of $7,000 (less applicable gross earning taxes—no gross-up is provided).

The MEA is yours to use as you wish, and no receipt submission to the RMC or PG&E is required. However, you may need to keep receipts for your personal tax records. If in doubt, keep your receipts and talk to a tax advisor.

The MEA will be distributed directly to you from the RMC via direct deposit or check once your signed Repayment Agreement has been received and you have started work in your new location. If you are a current employee, you will be responsible for updating your Personnel Change Request in order to receive your MEA.

The MEA may be used to help with expenses such as:

§ Storage or shipment of household goods outside of the parameters outlined in this guide

§ Alcohol, wine and wine cellar shipment

§ Tips to movers

§ Travel expenses not covered by relocation guide, e.g., airline upgrade fees, preferred seat fees, baggage fees for the home finding trip, and bags in excess of two per person for the final move trip, etc.

§ Concessions negotiated in the sale of a home

§ Express mail charges (Federal Express, UPS, Airborne Express, etc.); notary fees, etc.

§ Personal telephone calls (long distance, cell phone charges)

§ Repairs, decorating, installation, wiring, cleaning, landscaping, etc. expenses for old or new home

§ Security or utility deposits

§ Automobile registration fees, licenses, or smog control charges

§ Losses of fees for subscriptions, memberships, schools, safety deposit box

§ Child care expenses

§ Spouse/domestic partner employment costs

§ Pet deposits or moving and boarding of pets

§ Laundry and cleaning

§ Tax obligations not fully compensated by gross-up

§ GPS and other upgrades not standard for your rental car

Lease Cancellation

If you are a renter and have a lease to cancel in the departure location, you will be reimbursed for up to 2 months' rent.  Your lease must have been signed prior to the date of the official relocation.  The intent of this benefit is to cover lease cancellation fees, but not unused rent (i.e. if you are responsible for rent through a given month and move out midway through the month, the balance of that month's rent is not considered reimbursable as "lease cancellation").

Following is the documentation that you will need to submit for reimbursement:

§ A copy of the current lease signed by the landlord and tenant(s)

§ A copy of the notice to vacate letter that you provided to the landlord or property manager, which includes the date you intend to vacate

§ A response back from your landlord with the dollar amount required to break the lease and confirmation that you have vacated and turned in your keys.  The landlord will need to outline the costs (i.e. rent, break fee, etc.), associated with breaking the lease.

§ Proof of payment of the amount you paid to the landlord for the lease break.  This can be in the form of a cancelled check (front and back), credit card or bank statement showing the charge, or a signed/dated receipt from the landlord showing what was paid.

Upload all of the above documents to the website at www.altairglobal.com for reimbursement consideration.  Please provide all required documents together to avoid delays in reviewing your reimbursement.

Relocation Clause

If you decide to rent rather than purchase a home in the new location, you should include a relocation clause in your new lease that allows you to terminate the lease without penalty upon future relocation. The following example may be used:

It is understood the Lessee is subject to transfer by his or her employer. Accordingly, it is agreed in the event of Lessee's transfer at any time prior to the date on which the last monthly rental payment under this Lease becomes due, Lessor will release Lessee of and from all further obligations under the Lease as of the last day of the monthly rental period during which Lessee vacates the premises, provided the Lessee gives written notice to the Lessor 30 days prior to vacating.

Home Sale Assistance Program

For homeowners, the sale of your home may be one of the most critical factors in accomplishing a successful relocation. The Home Sale Assistance Program is structured to save money for you and PG&E by providing you the opportunity for significant tax savings.

You Must Work with Altair

To receive home sale benefits you must contact PG&E's Relocation Management Company (RMC), Altair, for referral to approved real estate agents in connection with the purchase and/or sale of your residence. If you choose not to use an Altair preferred broker, you may jeopardize your closing cost benefits.

Call the Relocation Management Company First!

800.934.5400

800

Eligibility of the Home

To be eligible for the Home Sale Assistance Program, your home must meet the following criteria:

§ The residence is a one-family or two-family home, townhouse or condominium on a standard size lot (less than one acre) and zoned residential.

§ The land on which the residence is located must constitute a lot of standard size for the area and zoned residential. Land not reasonably necessary for the use and enjoyment of the property as a single-family dwelling, such as additional lots or farm acreage, is excluded.

§ The home is your primary residence on the effective date of the transfer and you are currently living there.

§ You, or you and your spouse/domestic partner, are owner(s) of the property and you have good and marketable title to the property (an ex-spouse/domestic partner or parent cannot be on title).

§ The residence is in good and marketable condition.

§ The residence is not presently under renovation.

§ You know of no hidden or latent defects for which you might later be held responsible.

§ Mortgage payments, Real Estate taxes, and Association dues are current.

§ All required building permits and private road maintenance agreements are recorded.

§ Homes containing a well must have water rights, and the water supply must be both potable and ample under local standards.

§ Condominiums must meet the following guidelines:

- Only twenty percent (20%) of the total number of finished units are vacant and/or unsold.

- Only twenty percent (20%) of the units are owned by absentee investors for rental purposes.

- Association dues/Assessments per year (net of utilities) do not exceed two percent (2%) of the estimated fair market value of the condominium unit.

- The units in the complex are mortgageable by FNMA standards.

- The Condominium Association is in sound financial condition as evidenced by (I) current financial statements, (II) sufficient replacement reserves, (III) no rapid increase association dues and (IV) no unusual or excessive liens.

- You are responsible for providing verification of the above.

Some properties may not qualify for the Home Sale Assistance Program. The following list is not all inclusive, but provides some common examples:

§ Unusual homes such as geodesic domes, earth homes, log cabins, houseboats, A-frames, and other specialty homes

§ Rural residential zoning or lots larger than one acre

§ Cooperative apartments

§ Mobile homes and/or trailers

§ Residences that require an association's approval of purchaser

§ Secondary tracts of land

§ Farm properties

§ Homes with structural problems to the extent they are deemed, by a qualified structural engineer, to be unsalable

§ Homes that are ineligible for standard financing

§ Any home built with synthetic stucco; LP, composite, or  masonite siding (unless remediated); or containing any other materials which are involved in, or could be potentially involved in, a class action lawsuit

§ Homes with toxic mold or excessive levels of hazardous substances

§ Vacation homes

§ Investment properties

§ Apartment buildings

Other factors which may affect the eligibility of a property for this program include, but are not limited to, the following:

§ Legal/title problems (liens, judgments)

§ Property line issues (properties with private roads must have a recorded road maintenance agreement)

§ Structural problems/damage

§ Expansive soil

§ Safety or code violations

§ Unmarketable title

§ Inability to meet conventional lender or insurance requirements

§ Properties in foreclosure

§ Bankruptcy

§ Special financing (e.g., first-time buyers)

If your home is subject to any of the items listed above, inform your RMC consultant.

When you request the RMC's assistance, your home must be available for sale. It cannot have been rented or leased within the past 12 months. It cannot be rented or leased after you elect to participate in the Home Sale Assistance Program. All construction and/or repairs must be completed prior to requesting to participate in the Program.

PG&E RETAINS THE RIGHT TO MAKE THE FINAL DECISION ON THE ELIGIBILITY OF A HOME FOR THE HOME SALE ASSISTANCE PROGRAM.

If your home is ineligible for the Home Sale Assistance Program

In accordance with the criteria identified above, or by the judgment of the RMC and PG&E, you will be responsible for selling your home on your own.  You will still receive direct reimbursement for reasonable and customary home sales expenses.  For reference, a list of reasonable and customary home sale expenses covered by PG&E can be found on page 13.  Your home sales expense reimbursement will be grossed up.

If your home is eligible for the Home Sale Assistance Program

In accordance with the criteria listed above and you choose not to participate in the Home Sale Assistance Program, you will still receive reimbursement for reasonable and customary home sale expenses; however, none of the expenses of the transaction will be grossed up.

Step-by-Step Guide to Home Sale Assistance Program

You must follow these steps carefully to ensure compliance with the Home Sale Assistance Program. If these steps are altered in any way, your home sale assistance benefits may be at risk.

Step 1:Speak with your RMC consultant before signing any agreement(s) with real estate professionals regarding the sale of your home.

As soon as PG&E authorizes the RMC to provide services, your consultant will contact you to conduct an initial interview. This interview will include discussion of all aspects of your relocation benefits and the needs that you anticipate for your family during the relocation process.

Step 2:Broker's Market Analysis

After the initial interview, your consultant will order two Broker's Market Analyses of your home and review them with you. A Broker's Market Analysis (BMA) is performed by a real estate broker on the basis of his or her knowledge of the current real estate resale activity in the community. Each Analysis will compare your home with other similar, recently sold homes to attempt to answer the question:

"What will the home sell for in the next three to four months, as is, with usual financing for the area?"

The average value of the BMAs will be the basis for the initial listing price for your home under the Home Sale Assistance Program. The home should be listed for no more than 5% over the average of the two BMAs' most probable sales price. (Following the appraisal process, you will need to adjust your list price so that it is not more than 5% over the value provided in your Guaranteed Purchase Offer.)  Adherence to the Home Sale Assistance Program requirements, including list price caps, is necessary to receive the home sale assistance and home purchase benefits outlined in this guide.

Step 3:Selecting a broker or agent to sell your home

You may want to list your home with one of the brokers who provided a BMA, but you are not required to do so. Talk over your broker preferences with your RMC consultant. If you wish to consider additional brokers, the RMC will provide referrals. You are free to choose a broker or agent you already know, subject to RMC approval. Approval must be granted before you take any action regarding the price, terms and service requirements of the listing.  In addition, your agent may not be your relative (defined as a parent, child, spouse, domestic partner, sibling, in-law, stepparent, stepchild, grandparent, or grandchild) as it is a conflict of interest for the Company to reimburse members of a relocating family for services (commission) connected with the sale of the old home or purchase of a new home.

Step 4:Listing your home for sale

After you have chosen a broker or agent, you will be asked to sign a listing agreement. The following "Exclusion Clause" must be included as a signed addendum to your listing agreement:

"It is understood and agreed that regardless of whether or not an offer is presented by a ready, willing and able buyer:

(1) That no commission or compensation is earned by, or is due and payable to, broker until sale of the property has been consummated between seller and buyer, the deed delivered to the buyer and the purchase price delivered to the seller; and

(2) That the seller reserves the right to sell the property to Altair Global or any other person(s) designated by Altair (individually and collectively a "Named Prospective Purchaser") at any time upon which this listing agreement shall terminate without obligation by Altair or the parties to this agreement and no commission or compensation will be due."

The exclusion clause must be attached to the listing agreement as a signed addendum. This clause will prevent PG&E from paying the listing broker double commission when the home is sold.

The commission may not exceed 6% without prior approval from PG&E. The term of any listing agreement should not exceed 90 days. Your RMC consultant may recommend a shorter term under certain circumstances.

Establish a realistic list price for the home. Your RMC consultant will offer advice on the best listing and selling prices, based on current market data provided by real estate professionals in the community. You are encouraged to participate in this process by providing relevant data to the brokers chosen to assess value. The advantages of a competitive listing price will be explained fully by your consultant.

You must complete a home sale disclosure statement. Every home seller has certain legal duties and obligations to a buyer, including full disclosure of all pertinent information about the condition of the home and its surroundings. If the RMC inadvertently or without proper disclosure information purchases a home ineligible for the Home Sale Assistance program, and PG&E incurs a loss as a result of your omission or misrepresentation of information, you must repay PG&E any current and future out-of-pocket expenses, and/or fines or legal judgments paid or to be paid by PG&E with regard to the property.

You must not sign any purchase offers or accept any earnest money. Your relocation consultant will instruct you on how to proceed.

Step 5:Work closely with the broker and the RMC  to locate a buyer for your home.

Your RMC consultant will work directly with the real estate broker or agent to monitor progress in marketing your home. The consultant will make constructive suggestions and note any market activity that might impact the sales strategy. You will be contacted regularly by the consultant to discuss current information and revise the sales strategy as needed. You are encouraged to carefully evaluate these recommendations, but you are not required to accept them.

Step 6:Review any purchase offers on the home with your RMC consultant.

Signing any purchase offer or accepting any earnest money deposits from a buyer or broker prior to speaking with your RMC consultant will place your Home Sale Assistance benefits at risk.

You should contact your RMC consultant immediately when you receive any offer to purchase your home. Your consultant is available by phone toll-free during office hours or after hours by calling the number listed on his or her business card, and he or she will tell you what to do if the offer is acceptable to you.

If an offer from a buyer is acceptable, the RMC will sign the contracts. The RMC's obligation to you and PG&E is to determine if the buyer is qualified and if the offer is bona fide before approving the contract.

It is important to proceed with care in evaluating a purchase offer because some costs may not be reimbursable. If the buyer's purchase offer requires the seller to pay any concessions or buyer's expenses at closing those costs will be deducted from your equity. The following list provides guidelines for consideration as you negotiate a purchase offer; however, you should consult your RMC consultant if there is any question about whether a cost will be paid under PG&E's relocation benefit program.

PG&E Will Pay (if normally required of seller)

PG&E Will Not Pay

§Document preparation fees §Survey fees §Mortgage release fees §Recording fees §Transfer taxes §Title insurance §Closing and legal fees §Escrow fees §FHA/VA fees (required by seller) §Attorney fees, if an attorney is required to handle the actual closing §Termite or pest inspection §Radon inspection or warranty, if necessary §Normal and reasonable real estate broker's commission (not to exceed 6% of purchase price, unless approved in advance by PG&E)

§Discount points (FHA, VA or conventional) §Escrow §Insurance §Utility bills §Property taxes §Rent §Seller concessions included in the contract with the buyer, including buyer's closing costs, home warranties, repairs, remodeling, restoration or renovation of any kind §Expenses to remedy and bring to acceptable standards hazardous conditions in the home, such as: -Radon gas -Friable asbestos -Lead-based paint -Urea formaldehyde foam insulation -Underground storage tanks containing toxic materials -Similar environmental hazards -Pest control

Step 7:Amended Value Sale

Amended Value Sale is a procedure that will be used when you find a buyer for your home. The Amended Value Sale Program consists of two separate, arm's length transactions:

§ The RMC purchases the home from you at the same net price and terms as the bona fide offer that you have received from a buyer. Once the sale to the RMC closes and you vacate the home, subject to disclosure obligations, you are no longer financially or legally responsible for the home.

§ The RMC, as the owner of the property, sells the home at the previously offered price to the buyer who made the offer. If something should happen to prevent this second sale from taking place, you are not affected.

Because the RMC, on behalf of PG&E, is buying your home based on the value of the offer you have received, the RMC must be sure that the offer is bona fide and that the buyer is ready, willing and able to purchase your home. Your consultant will work closely with you and your broker as you consider any offers to be sure that the terms are acceptable to the RMC and PG&E.

In order for an offer to be eligible for the Amended Value Sale Program, it must meet certain requirements, including:

§ The contract of sale from the buyer must specify a closing date that is within 60 days of the contract date.

§ The contract must not be contingent on the sale of the purchaser's home. It can, however, be contingent on a closing scheduled to occur within thirty (30) days of the contract date.

§ The contract must not contain other contingencies, with the exception of inspections and buyer's approval for financing.

If the RMC cannot accept the contract of sale because the buyer is not qualified with a bona fide offer, you must continue to market the home.  If you choose to accept the contract of sale with the buyer against the recommendation of the RMC, you will be responsible for managing the process as an independent sale, outside of the Home Sale Assistance Program.  In this case, you will still receive direct reimbursement for reasonable and customary home sale expenses; however, none of the expenses of the transaction will be grossed up.

Step 8:Closing an Amended Value Sale

When an acceptable offer to purchase the home has been received, documents previously sent by the RMC will require immediate attention. The documents will include a contract of sale between you and the RMC, certain financial information forms and a general warranty deed that will subsequently be used by the RMC to convey title. Your consultant will offer specific advice as required, but you (and your spouse, if applicable) should plan to execute the documents as soon as possible before a Notary Public and return them to your RMC consultant. It will not be necessary for you to attend the closing of the sale.

You will receive your equity directly from the RMC when the Contract of Sale documents are signed or the property is vacated, whichever is later. Payment will be by either check or electronic transfer. You will also receive a detailed equity statement by email, mail, or fax explaining every adjustment to the equity. In general, the equity will be calculated as follows:

Guide for Calculation of Equity
To determine the total "net" cash value of any transaction on the home under the Home Sale Assistance Program, first add together:	1.The purchase price appearing in the RMC's contract of sale, wherein you are the seller and the RMC is the purchaser. 2.Any amounts you have prepaid for which you are entitled to receive a prorated refund, such as interest and taxes, but excluding home casualty insurance.
Then subtract from the above the total of the following amounts (if any) that are applicable:	1.All outstanding indebtedness (mortgages, tax liens, judgments, etc.) 2.Charges for prorated items such as interest and taxes through the effective date of the contract of sale between you and the RMC or through the vacate date, whichever is later. 3.Concessions to which you agreed as the seller. 4.Costs for deferred maintenance/repairs to be completed before the home can be purchased. 5.A vacate holdback of $500, refundable to you after you have permanently vacated the property and the RMC has verified property condition.
The difference is:	The net equity under the Company relocation program.

Step 9:Cost of Ownership

The sale price in the Contract of Sale between you and the RMC will reflect the cost of ownership of the home (property insurance, taxes, utilities, maintenance and interest on the mortgage) through the effective date of the contract of sale between you and the RMC or the vacate date, whichever is later. The equity statement from the RMC will provide a detailed accounting of your home sale transaction.

It is acceptable to cancel your property insurance as of your vacate or acceptance date, whichever is later. However, for liability purposes it is recommended that your property insurance remain in effect until your new policy is in force. It is your responsibility to contact your insurance carrier to advise them of cancellation.

Your RMC consultant will advise you when to discontinue making mortgage and other payments. If you have arrangements with any lender for payments to be automatically deducted from your account, it will be your responsibility to cancel the automatic draft(s) as of your acceptance or vacate date whichever is later. It is imperative you discuss with your RMC consultant when to send this form to your lender. If you fail to cancel your automatic draft(s), refunds for overpayments will be delayed until after closing.

Step 10:Vacating the Home

If you vacate prior to closing, your real estate broker will make arrangements to pick up your house keys, warranties, garage door opener controls and other such necessities. Your consultant will notify you when to transfer utilities to the broker's name, but do not request the utilities be turned off as this will result in reconnect charges. Please be sure to contact the utility companies to provide your forwarding address for your final bills.

Regardless of whether you vacate before or after closing, it will be necessary to leave the home in cleanly swept condition. In order to avoid paying additional cleaning charges later, the home must be clean and you must remove all personal property, trash or debris. Cleaning charges will be withheld from the refund of your "vacate holdback" (Step 8, item 5 in the Guide for Calculation of Equity) if necessary.

Tax Liability

The majority of expenditures associated with this benefit are not reported as gross earnings; thus no gross-up is necessary provided the home sells under the Amended Value Sale program. The only exception to this is the expenditures associated with the deed and transfer tax of the property in some states.

Guaranteed Purchase Offer

Once your home is listed under the Home Sale Assistance Program, the RMC will guarantee to purchase your home at a price based on objective relocation appraisals. With this Guaranteed Purchase Offer (GPO), it is possible for you to move with confidence, knowing you may accept the RMC's offer if further marketing under the Home Sale Assistance Program does not bring an acceptable outside buyer.

Required Marketing Period

You are required to market your home under the Home Sale Assistance Program for 60 days before you may accept the Guaranteed Purchase Offer. The required marketing period begins on the day you list your home for sale under the Home Sale Assistance Program.

Relocation Appraisals determine the value of the Guaranteed Purchase Offer.

When you have begun to market your home under the Home Sale Assistance Program, you will be asked to select appraisers from a list presented by your RMC consultant. The appraisers will be local, independent appraisers who, once selected, will be hired by the RMC to appraise your home.

The primary intent of PG&E's Home Sale Assistance Program is to assist you in locating a buyer, not to purchase and re-sell your home. Therefore, the appraisers are asked to objectively evaluate your home in order to estimate the most probable selling price after reasonable market exposure. This definition of value differs from a bank or mortgage appraisal and may also differ from what a specific buyer might be willing to pay for your home. The GPO is provided as a fall-back offer, available to you if you do not locate a buyer. Through the RMC, PG&E will purchase your home at a price that should enable the RMC to re-sell it within a reasonable amount of time.

You will be thoroughly briefed on the content of the appraisals by your relocation consultant.

The amount of the Guaranteed Purchase Offer will be the average of the two appraisal values. If the lower value of the two appraisals is not within 5% of the higher value, the RMC will ask you to select another appraiser and will order a third appraisal. When this occurs, the Guaranteed Purchase Offer amount will be the average of the two closest values. (The Brokers' Market Analyses, discussed previously in the "Home Sale Assistance Program" section, will not be included in the average.)

The appraised value is contingent on the results of any customary and required inspections. Repairs identified through these inspections are your financial responsibility. Repairs must be completed before equity is released or the cost of repairs will be deducted from your equity. Repairs are subject to re-inspection. Repairs identified will be defects (i.e., leaks, faulty furnace or water heater, etc.) and do not include cosmetic items such as painting or replacing carpet, unless those items are required by a lender.

In the process of appraising your home, the appraisers will review comparable sales selected from a multiple listing service or similar directory. You are encouraged to provide appraisers with a list of recent, comparable sales or other related data that may be useful in assessing the value of your home.

Within seven days of receiving your Guaranteed Purchase Offer, you must reduce your list price to no more than 105% of the GPO amount.  Adherence to the Home Sale Assistance Program guidelines, including list price caps, is necessary to receive the home sale and home purchase benefits outlined in this guide.

Accepting the Guaranteed Purchase Offer

You may accept the GPO at the end of the 60-day marketing period, or you may continue to market the home until the end of the acceptance period of the GPO. The acceptance period of the GPO is 60 days, beginning with the date of the offer (not necessarily the same date as the marketing period begins).

To accept the GPO, execute the contracts and all associated documents (which may differ depending on which state the home is located). Several of the documents will require the acknowledgment of a Notary Public. All documents must be in the RMC's possession before the end of the 60th day.

The equity payments based on the GPO will be made on the later of either the contract date (when the contract is signed by your relocation consultant) or the date the home is vacated. Allow five (5) business days after the RMC receives paperwork for payment of the equity. The RMC will deliver the equity check to you by overnight service or wire the funds directly to the account.

Amended Value Sale

If, before accepting your GPO, you receive an offer from an outside buyer that you wish to consider, work with your broker and your RMC consultant to negotiate the offer so that it may be closed as an Amended Value Sale. (See previous discussion of this procedure in the "Home Sale Assistance Program.")

Home Sale Incentive

Should you receive an offer from an outside buyer that is less than the GPO amount, terms may be negotiated for an amended value sales price that is no less than 95% of the GPO amount. In this case, you may accept this offer and still receive the full amount of the GPO.  You will also receive a bonus of 1% of the negotiated sales price, up to a maximum of $10,000, less applicable taxes.

Possession Period

You will be given thirty (30) days from acceptance of the GPO or Amended Value Sale to vacate the property.

Proration Date

If you accept the GPO, you will be responsible for insurance, taxes, utilities, maintenance, principal and interest on the mortgage through the date of acceptance of the GPO or the date the property is vacated whichever is later.

Pass-back of Gain or Loss on Sale to Employee

Under the terms dictated by the Internal Revenue Service, if the employee accepts the GPO and the property ultimately sells for more than the employee's GPO buyout, a pass-back of a gain (or a loss) is not permitted. The sales are treated as two separate sales transactions and cannot be related.

Tax Liability

The majority of expenditures associated with the GPO benefit are not reported as gross earnings; thus no gross-up is necessary provided the home sells under the Guaranteed Purchase Offer program. The only exception to this is the expenditures associated with the deed and transfer tax of the property in some states.

However, the Home Sale Incentive is reported as additional gross earnings. No tax assistance is available and appropriate taxes will be withheld.

Equity Advance

The Company may grant you an equity advance in the form of a loan for up to 90% of the equity in your current home when the equity is required to guarantee a contract on a home in the new location. The advance is made to accommodate your being transferred at the request of the Company, and it is not a mortgage loan. The following guidelines apply:

§ The advance will equal no more than 90% of the equity based on the Guaranteed Purchase Offer.

§ The total amount of the advance must be used exclusively toward the purchase of a new residence.

§ You must sign a promissory note and agree to repay the advance upon completion of the sale of the former residence. The term of the promissory note is 120 days.

If you are an executive of the Company as defined by the Sarbanes-Oxley Act, your equity will be disbursed at the time you accept the Guaranteed Purchase Offer and execute the required paperwork.

Tax Liability

This benefit is not reported as gross earnings, and no gross-up is necessary.

New Home Finding Assistance

Do not contact any real estate professional at the destination without the guidance of your RMC consultant. When you are ready to visit your destination to look for suitable housing, the RMC must arrange your travel and lodging and take care of many of the details for you.

PG&E will provide you with assistance in searching for your new residence. Specifically:

§ Before you depart to look for housing in the new location, your RMC consultant will ask you for detailed information concerning your housing preferences, price range and family requirements.

§ If you wish to rent, the RMC will arrange for a rental service or a real estate broker to assist you in locating the right place for you.

§ If you choose to purchase a home, a real estate broker will arrange for house-hunting tours for every day you are in the area. You will be escorted to neighborhoods and homes of interest to you. Through your broker or agent, you will see homes targeted to meet your goals and needs.

Rental Assistance

In order to assist employees who intend to rent or lease a home or apartment in the new location, one full day tour with a rental finding company/brokerage will be provided. Your RMC consultant can assign you to a qualified local company in your destination area to provide you with the following information:

§ General availability of apartments, houses, and condominiums for rent and the range of rental rates

§ Local real estate practices governing such matters as who prepares the lease, the amount of commission if any, and the security deposit required

Home Search Trip

You and your spouse/registered domestic partner may take up to two home search trips for a maximum of eight days, seven nights total. Dependent children who will be relocating to the destination with the family will also be eligible for one home finding trip.

The following conditions apply to travel expense reimbursement:

§ All travel arrangements must be made through the RMC.

§ Itemized receipts are required for reimbursement. Submit the Expense Report to the RMC.

§ Airline reservations should be made seven days in advance. If you wish to drive, you will be reimbursed mileage at the current IRS rate for business travel.

§ Baggage fees are not reimbursable for this trip. You may use your Miscellaneous Allowance to cover baggage fees.

§ Expenses for transportation to and from the airport, parking, and tolls will be reimbursed in accordance with the Company business travel policy.

§ Reasonable lodging will be provided for employee and spouse/domestic partner together for the trip.

§ Expenses for car rental and gas will be reimbursed. Expenses for a GPS or upgrades not standard for the rental car will not be reimbursed.

§ Meals up to $75 per day per adults and children aged 16 and older and $40 per day per child under the age of 16. Costs for alcoholic beverages will not be reimbursed.

§ Do not use your corporate credit cards for relocation expenses. In addition, do not use your company car for activities related to relocation, as the IRS considers such use as taxable income to you.

Business Expenses

Should you incur business expenses during the home finding trip, these expenses must be segregated from relocation expenses and submitted to PG&E separately to avoid relocation tax liability.

Tax Liability

New Home Finding benefits are reported as additional gross earnings and the amount is grossed up to help offset additional taxes.

Lender Referral

One of the critical aspects of buying a new home is obtaining mortgage financing. The RMC will provide you with a list of representatives of selected local and national mortgage companies that will offer loan programs for your use. You are not required to use any of the lenders referred by the RMC, but they typically offer mortgages at competitive interest rates and reduced fees. Your designated mortgage company will provide details on financing your transaction.

Home Purchase Closing Costs

You are eligible for reimbursement of normal closing costs when you purchase a home at the new location. To receive this benefit you must close the purchase of your new home within one year of your report date at the destination location. If you choose not to use an Altair preferred broker, you may jeopardize your closing cost benefits.

Closing Procedures

Your mortgage company will provide details on financing your transaction.

Your consultant will review your closing documents to make certain that the charges are in order, consistent with your negotiated purchase contract and within the limits of reimbursements that will be paid by PG&E.

All eligible costs will be paid by the RMC at closing so that all you need to provide when you close the purchase of your home is the down payment and any concessions or other non-eligible costs.

Eligible Closing Expenses

Closing costs reimbursement will be equal to actual costs or 2.0% of the new home purchase price, whichever is less.

§ Appraisal fee, if required by lending institution

§ Credit report

§ Settlement or closing fee

§ Title insurance

§ Document preparation

§ Notary fee

§ Attorney's fees

§ Government recording and transfer charges (only if required of the lender)

§ Survey (only if required of the lender)

§ General home inspection

§ Pest or termite inspection (only if required of the buyer)

§ Application fee, commitment fee, processing fee, etc.

Note: The items listed above are not all inclusive. Eligible expenses may vary by local custom. Your RMC consultant will advise you regarding expenses covered by PG&E.

Non-eligible Closing Expenses

Specifically excluded from reimbursement are prepaid expenses such as:

§ Prorated interest

§ Discount points

§ Loan origination fees

§ Taxes

§ Homeowner's insurance

§ Mortgage insurance

§ Earnest money payments

§ Property mortgage insurance for insufficient down money

§ Tax or insurance escrow

§ Home warranties

§ Any fees associated with second mortgages

Tax Liability

The Closing Cost Benefit is reported as additional gross earnings and the amount is grossed up to help offset additional taxes.

Household Goods Moving

Your belongings will be shipped by one of the RMC's select moving companies.

Your consultant will arrange for the RMC's household goods move coordinator to contact you and provide you with details surrounding the movement of your household goods. The moving company will need sufficient time to properly coordinate your move. A minimum notice of 30 working days is required.  During holidays and summer months, more lead-time is required.  Packing and loading dates will be arranged with every attempt made to provide these services on the dates you request. However, keep in mind that PG&E will not authorize or reimburse additional costs of weekend or holiday service. If you request a weekend or holiday move, the overtime charges will be collected directly from you upon delivery.

Insurance

Replacement cost insurance up to $100,000 is provided at no cost to you. If you require additional coverage in excess of that provided, the cost will be billed to you by the RMC.

Moving Services

The selected household goods carrier will pack, load, insure, transport, deliver and unpack your normal household goods. There are some limits to this service. Furniture and boxes will be placed in your home where specified, and the contents of your boxes will be unpacked and placed on the closest flat surface, if requested. Unpacking beyond this description is considered a settling-in service or maid service and may be obtained from the moving company at an additional cost to you.

Depending on the complexity of services you require, some additional services may be performed by your moving company or a third-party service firm when deemed necessary by the RMC and within reasonable costs. Such "third-party" services, including crating, will be considered for normal household goods only and will not include service for items affixed to the property.

It is strongly recommended that you take advantage of the packing services provided by this guide. If you pack yourself, no cost saving is realized and none of the goods that you pack will be insured.

If you are unavailable for a pick-up or delivery and do not notify movers in advance, any additional charge will be billed to you.

Household Goods Storage

Storage of household goods and personal effects in transit will be covered up to 90 days, but only if storage is unavoidable. If storage is required for more than 90 days or if you need to access any stored items, the charge will be billed to you.

You will be responsible for costs beyond the time period allowed by this guide.

Transportation of Automobiles

PG&E will pay for shipping up to two personal automobiles if the move is greater than 400 miles. The vehicles must be in working order and must fit on a standard car carrier or moving van. The value of the vehicles to be moved must exceed the cost of shipment.

If the move is less than 400 miles, you are required to drive the cars you own to the new location or ship them at your own expense. Mileage and tolls via the most commonly used direct route will be reimbursed at the current IRS rate.

Disconnecting and Connecting Appliances/Utilities

PG&E will cover the cost of disconnecting and connecting normal household appliances or any other article requiring special servicing for safe transportation. Appliances include washer, dryer, refrigerator, and icemaker. However, the extension of any gas or electric lines or adding service for mismatched appliances (i.e., converting an electric hook-up for a gas appliance) is excluded.

Special or Extraordinary Shipping Requirements Are Your Responsibility

Plans should be made in advance for items requiring special or extraordinary handling. These shipping arrangements and the costs will be your responsibility, but call your household goods move coordinator or your relocation consultant for advice.

PG&E will not pay for charges by the moving company to pick up any furnishings or material at any site other than your primary residence. You will be billed directly for this additional service.

Authorized Household Goods Eligible for Moving Benefit

§ Clothing and personal items

§ Furniture and fixtures (not attached to the house)

§ Major appliances

§ Gardening equipment

§ Pianos (tuning, servicing and special handling are not included)

§ Grandfather clocks

§ Pool tables

§ Waterbeds (if drained and disassembled)

Items NOT Authorized

Please refer to the Domestic Moving Guide and Insurance Guide provided by your household goods move coordinator for a complete list of items that are not eligible for the moving benefit. The following is a list of items for which PG&E will not authorize transportation.

§ Boats, trailers, airplanes, motorcycles 250 cc and over, snowmobiles, off-road vehicles, travel trailers, pop-up trailers, camper inserts for pick-up trucks, or other recreational vehicles

§ Livestock or domestic animals

§ Frozen/perishable foods

§ Alcohol, wine and wine cellar shipment

§ Liquids in unsafe containers/flammable liquids, items that may contaminate or damage other goods

§ Valuable papers/securities/money

§ Valuable jewelry/precious stones/firs/items of extraordinary value

§ Heavy machinery/tractors/farm equipment larger than normally required for yard and garden maintenance

§ Lumber or other building materials

§ Plants

§ Antiques and fine art

§ Animal-drawn carriages or wagons, vintage and show automobiles

§ Storage sheds, greenhouses, play houses or other outside buildings

§ Campers, motor homes, livestock trailers

§ Satellite dishes greater than 24" in diameter/ solar panels

§ Coins, stamps and other fine collectibles

§ Items associated with an in-home business

§ Hot tubs/spas/above-ground pools

§ Ammunition and/or explosives

§ Firewood/coal

§ Items from a temporary residence

§ Items that cannot be attached a value (personal paints, pottery, etc.)

§ Auto parts

§ Any other items which cannot be packed or moved by a standard commercial carrier

§ Any goods/materials prohibited by law

Note: Gas grills may be shipped but must be emptied and certified before loading.

Additional Exclusions

§ Maid service or housecleaning service

§ Tips to movers

§ Disassembly/assembly of swimming pools, swing sets, basketball goals, or similar personal property

§ Insurance for items of extraordinary value such as antiques, fine art, coin and stamp collections, precious metals, documents, securities and notes, or insurance above the coverage provided by PG&E.

§ Disassembly/assembly of play gyms, television/radio antennas, chandeliers, flagpoles, etc. If such items are disassembled prior to packing, they may be transported. If movers assemble or disassemble unusual items, you will be billed directly.

§ Draining and refilling of waterbeds.

§ Establishing services such as power, water, gas, telephones, etc.

§ Exclusive use of moving van or space reservation

§ Unauthorized extra pick-ups or deliveries

§ Unauthorized overtime packing and unpacking

§ Unauthorized crating

§ Storage of automobiles

Important Information Concerning Household Goods Shipping

§ Valuables such as jewelry, coin and stamp collections, computer programs, currency, precious metals, gems or semi-precious stones, rare documents, or most other collectibles should be set aside and transported with you when you travel. Only under certain very specific conditions is the mover responsible for these items. Be certain to ask the representative of your moving company about transporting valuables when he or she visits your home to inventory your belongings.

§ Firearms may be transported, but must be unloaded, packed separately and inventoried by type of firearm and serial number. The inventory must be included in the documentation of the move. This is for your protection as well as the protection of the mover. You will be responsible for meeting the licensing or registration requirements, if any, of the state where you are moving. You cannot ship live ammunition via household goods movers.

§ Accompany the mover through the home as he or she inventories and tags each item to be moved. Plan to check off the items at the destination as well; otherwise, you may have difficulty with claims settlements should they prove necessary.

§ You or your representative should be present during packing and loading. Do not release the drivers until a complete inspection of the home and property has been accomplished, since items left behind could result in extra charges to you.

§ Detach items that are to be moved, such as televisions, wall-mounted can openers and coffee makers, pictures, posters, curtain rods, attached bookcases and the like. Unplug appliances and electrical devices such as stereos and computers; if possible, stow the connecting cords and cables.

§ Remove all items from refrigerators. Unplug, defrost, clean and let stand open to dry at least 24 hours in advance of loading.

§ Items that cannot be moved by your household goods mover:

- Bleach

- Propane tanks or butane tanks

- Flammable or combustible items of any kind, including gas and oil in lawn mowers, edgers and other yard or utility equipment

- Open liquids of any kind

- Frozen foods

- Aerosol cans or paints

§ No mover will accept liability for moving plants. If you choose to allow the mover to move your plants, you do so at your own risk.

Note: Federal regulations require that plants moved interstate be inspected and certified free of pests and diseases. The states of California, Arizona and Florida are especially diligent in enforcing their agriculture laws. Taking plants into these states may require considerable extra expense and effort.

§ If you have items in temporary storage, please give the shipper maximum possible advance notice of the date you prefer delivery. Fourteen days is recommended to ensure the availability of your preferred dates.

§ Keep your utilities on at the old location until at least the day after the scheduled completion of packing and loading.

§ In the event damage occurs during the shipment of your goods, please advise your relocation consultant within 30 days from you final delivery date. All claims must be submitted within 90 days of delivery date.

Tax Liability

Household goods moving expenses and storage up to 30 days are excluded from gross earnings and no tax liability is created; therefore, gross-up is not necessary. The cost of eligible storage beyond 30 days is grossed up.

Temporary Living Expenses

If you assume duties at the new location before your new home is available for occupancy, the RMC will arrange for temporary accommodations in corporate housing for up to six months as long as you are still financially responsible for your former residence. Temporary living must be arranged through the RMC.

Only lodging expenses will be covered, this includes one parking space at the temporary housing unit.

If temporary housing that allows pets is available, you are responsible for pet deposits, related fees, etc.

You are eligible for a rental car for up to 14 days while your personal auto is in transit. The rental car can be arranged through Altair's Travel Department and direct billed to Altair.

Trips Home

The Trip Home benefit is intended to provide you (the employee) with one trip back to your former residence so that you can meet with movers and assist your family with the final move.

You will be eligible for a maximum of two round trips for you, the employee, to return to the departure location OR your spouse/registered domestic partner to visit the destination location. Only round trip airfare or mileage (the most direct route driving at least 400 miles per day) is eligible for reimbursement for your Trip Home benefit. Items that will not be reimbursed include; transportation to and from the airport, parking, meals and baggage fees. The Miscellaneous Expense Allowance is intended to cover these costs.

Tax Liability

This benefit is reported as additional gross earnings and the amount is grossed up to help offset additional taxes.

Final Trip

Reimbursement will be provided for reasonable in-transit expenses incurred by you, your spouse/registered domestic partner, and eligible dependents while traveling on the final trip from the old to the new location.

Eligible expenses include reasonable travel, such as a shuttle or taxi to the airport, lodging and meal expenses. Meals up to $75 per day per adults and children aged 16 and older and $40 per day per child under the age of 16. Costs for alcoholic beverages will not be reimbursed.

You must work with your RMC consultant to make your travel arrangements. Air transportation (coach class with advance purchase) will be provided if the distance is over 400 miles; otherwise you are required to drive to the new location. Baggage fees for up to two pieces of regular luggage per person will be eligible for reimbursement. You may be reimbursed for up to $100 in total per person for baggage fees. Any additional baggage fees should be paid for using your Miscellaneous Allowance.

If you drive, you will be reimbursed mileage for up to two automobiles. Mileage reimbursement will be based on the current IRS rate for business travel by the most direct route. Other expenses for hotel and meal reimbursement will be based on travel of at least 400 miles per day. No reimbursement is provided for the additional cost of side trips or sightseeing.

Expenses are reimbursable for one night prior to departure, en route, and if you are unable to move directly into your new home upon arrival, one night at the destination.

Do not use your corporate credit cards for relocation expenses. In addition, do not use your company car for activities related to relocation as the IRS considers such use as taxable income to you.

You must report actual travel expenses on a Relocation Expense Form and submit to the RMC for approval.

Tax Liability

With the exception of meals and excess mileage in accordance with IRS guidelines, final move expenses are excluded from income and no gross-up is necessary. Meals and excess mileage payments are reported as additional gross earnings and are grossed up.

Expense Reporting

In some circumstances, you are required to pay certain relocation expenses and request reimbursement afterward. Such reimbursement requests must be kept separate from other business expenses and submitted to the RMC, using the Relocation Expense Form.

After submitting the expense report online, the required receipt copies should be submitted to the RMC for approval and processing no later than 30 days after you incur the expenses. Failure to submit expenses within this time frame could jeopardize reimbursement, your tax assistance, or both. Reimbursement will be for actual, reasonable costs only, within the guidelines.

Please remember:

§ You must include copies of itemized receipts for all expenses in order to be eligible for reimbursement.

§ You must include a copy of the expense report when you provide your receipts.

§ It is wise to make copies of all reimbursement forms and receipts that you submit for your personal records as well as for income tax purposes.

Regular business/travel expenses must be submitted separately to PG&E on separate expense reports.

Do not use your corporate credit cards for relocation expenses. In addition, you may not use your company car for activities related to relocation, as the IRS considers such use as taxable income to you.

In addition to other policy provisions regarding the timing of expense reimbursements, any reimbursements of taxable expenses provided pursuant to this program shall be reimbursed on or before the last day of the calendar year following the year in which the expense was incurred, consistent with requirements in Internal Revenue Code Section 409A, as it may be amended.

The amount of expenses eligible for reimbursement is not subject to a multi-year cap.  As a result, expenses eligible for reimbursement during one year do not affect the expenses eligible for reimbursement in any other taxable year.

Tax Liability on Relocation Expenses Paid to You or On Your Behalf

Most of the amounts expended by PG&E on your behalf during relocation, whether reimbursed to you or paid directly to the service provider, will be included in your annual income. The only exceptions are certain household goods moving and final trip expenses, defined by the IRS, which are excluded from your income. Other than these specific, limited exclusions, the total of all other relocation payments will appear on your W-2 issued in January of the following year.

PG&E will provide tax assistance for most taxable benefits through a process called "gross-up." The RMC will calculate the amount of gross-up to which you are entitled and report it to PG&E. PG&E, through the payroll department, will pay additional funds directly to the appropriate tax authority to help offset the tax liability.

Please take note of these important factors pertaining to your gross-up benefits:

§ The tax assistance provided by PG&E will be calculated using supplemental federal, state and local rates and will include Social Security and Medicare if applicable.

§ Certain relocation expenses, which are not grossed up, may be deductible on your individual tax return.

§ Gross-up is provided as a financial benefit, but is not intended to compensate you completely for all tax liabilities.

§ You are responsible for calculating, reporting and paying all personal federal, state and local income taxes for which you are liable. The RMC will send you a detailed gross-up package that itemizes all relocation expenses for the tax year, including the gross-up payments the Company provides on your behalf. The package is provided for your information and for use by your tax professional if you use such services.

The services of tax and legal professionals are recommended.

RELOCATION REPAYMENT AGREEMENT

I hereby acknowledge that I have received and read a summary of the relocation assistance benefit available to me under the Pacific Gas & Electric Company (PG&E) relocation guide.  I understand the benefit to me of the assistance available and agree to the following:

· For purposes of this Agreement, the effective date of relocation is the first day I report to my PG&E work location.

· The payment of relocation costs directly to me and to others on my behalf by PG&E is conditional upon the successful realization of my physical relocation as requested by PG&E and upon my remaining in the employment of PG&E for a period of 24 consecutive months from the effective date of relocation.  If I voluntarily resign or retire my employment with PG&E prior to the completion of 24 consecutive months from the effective date of relocation, I will repay PG&E all relocation costs made to me or to others on my behalf, in accordance with the following schedule:

From the effective date of relocation, if I resign within:  12 months - I will repay 100%

           24 months - I will repay   50%

· If PG&E pays relocation costs to me or to others on my behalf but I do not physically relocate as requested by PG&E within the specified timeframe, I understand that PG&E will recover up to the full amount of relocation costs provided to me or others on my behalf. I understand that if I voluntarily resign or retire my employment with PG&E prior to 24 consecutive months from the effective date of my relocation, in addition to notifying my supervisor, I must notify PG&E's Relocation Services Department at relocationservices@pge.com.  Relocation Services will inform me of the amount of my relocation repayment obligation within five business days.

· I understand that any relocation repayment obligation I have pursuant to this Agreement is due and payable within 30 days of the notification of my resignation or retirement to relocationservices@pge.com or my last day of work, whichever is earlier.  I understand that if I fail to pay PG&E the full relocation reimbursement obligation within 30 days of notification of my termination to relocationservices@pge.com, or my final day of work, PG&E will submit the debt to a collection agency.

· Any dispute regarding any aspect of this Relocation Repayment Agreement, including its validity, interpretation, or any action which would constitute a violation of this Agreement shall be resolved by an experienced arbitrator, selected by PG&E and me (collectively "the parties") in accordance with the rules of the American Arbitration Association.  The fees of the arbitrator and cost associated with producing a transcript of the proceedings shall be paid in equal shares by the parties.  Any decision rendered by the Arbitrator, including any remedy awarded, shall be in accordance with the laws of California.

· The forum for any dispute submitted to arbitration pursuant to this agreement shall be San Francisco, California.  The decision of the arbitrator shall be final and binding.  Judgment may be entered thereon in accordance with the practice of any court having jurisdiction.

· Reimbursement of relocation expenses by PG&E does not constitute a commitment by PG&E with respect to the duration of my employment, or alter my at-will employment status.

· If any of the provisions contained in this agreement is held to be unenforceable, in whole or in part, by a court of competent jurisdiction, the entire agreement shall not fail and all other provisions and obligations of this agreement shall remain valid and enforceable.

By signing below, I hereby acknowledge and agree to the terms and conditions contained herein and confirm my intent to relocate.

______________________________

Print Name

_______________________________________________________

Employee signatureDate

EX-10.42

PG&E Corporation

2014 Long-Term Incentive Plan

PG&E Corporation

2014 Long-Term Incentive Plan

(As adopted effective May 12, 2014, and as amended effective January 1, 2016)

1.Establishment, Purpose and Term of Plan.

1.1Establishment.  The PG&E Corporation 2014 Long-Term Incentive Plan (the "Plan") is hereby established effective as of the date approved by the shareholders of the Company (the "Effective Date").  This Plan replaces the PG&E Corporation 2006 Long-Term Incentive Plan.

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 no Awards remain outstanding under the Plan.  However, the term during which all Awards shall be granted, if at all, shall be within ten (10) years from the Effective Date.  Moreover, Incentive Stock Options shall not be granted later than February 19, 2024 (ten (10) years from the date on which the Plan was adopted by the Board).

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 (which may also be in electronic form).

(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 thirty percent (30%) 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 (1) who were Directors at the beginning of the period or (2) whose election or nomination was previously so approved; or

(iii)the consummation of any consolidation or merger of the Company other than a merger or consolidation which would result in the holders of the voting stock of the Company outstanding immediately prior thereto continuing to directly or indirectly hold at least seventy percent (70%) of the Combined Voting Power of the Company, the surviving entity in the merger or consolidation or the parent of such surviving entity outstanding immediately after the merger or consolidation; or

(iv)(1) the consummation of any 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) the approval of the Shareholders of the Company of a plan of 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)"Non-employee Director" means a Director who is not an Employee.

(u)"Non-employee Director Award" means an Award granted to a Non-employee 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 in an unbroken chain of corporations ending with the Company in which each of the corporations other than the Company owns stock possessing 50% or more of the total combined voting power of all classes of stock in one of the other corporations in such chain.

(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 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)"Prior Plan" means the PG&E Corporation 2006 Long-Term Incentive Plan.

(kk) "Restricted Stock Award" means an Award of Restricted Stock.

(ll)"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 or payment equal to the value of 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.

(mm)"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.

(nn)"Retirement" means termination as an Employee with the Participating Company Group 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.

(oo)"Rule 16b‑3" means Rule 16b‑3 under the Exchange Act, as amended from time to time, or any successor rule or regulation.

(pp)"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.

(qq)"Section 162(m)" means Section 162(m) of the Code.

(rr)"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.

(ss)"Securities Act" means the Securities Act of 1933, as amended.

(tt)"Separation from Service" means a Participant's "separation from service," within the meaning of Section 409A of the Internal Revenue Code.

(uu)"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 ninety-first (91st) day following the commencement of such leave the Participant's Service shall be deemed terminated and 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 commencing on the third (3^rd) month from such deemed termination, 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.

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

(ww)"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.

(xx)"Subsidiary Corporation" means any present or future "subsidiary corporation" of the Company in an unbroken chain of corporations beginning with the Company in which each of the corporations other than the last corporation owns stock possessing 50% or more of the total combined voting power of all classes of stock in one of the other corporations in such chain.

(yy)"Substitute Awards" means Awards granted or Shares issued by the Company in assumption of, or in substitution or exchange for, awards previously granted, or the right or obligation to make future awards, in each case by a company acquired by the Company or any Subsidiary Corporation or with which the Company or any Subsidiary Corporation combines.

(zz)"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.

(aaa)"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, or other deadline for satisfying such conditions, as applicable.

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, Non-employee Director Awards shall be granted automatically pursuant to Section 7 of the Plan, and other Awards to Non-employee Directors shall be approved by the Board);

(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 any 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, subject, in the case of an adversely affected Award, to the affected Participant's consent unless necessary to comply with any applicable law, regulation, or rule;

(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, and subject to limitations set forth in Section 3.6;

(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, another Award, cash or a combination thereof (other than in connection with a Change in Control), (b) the amendment of outstanding Options or SARs to reduce the exercise price thereof, (c) the purchase of outstanding unexercised Options or SARs by the Company whether by cash payment or otherwise, or (d) any other action with respect to an Option or SAR that would be treated as a repricing under the rules and regulations of the principal U.S. national securities exchanges on which the Stock is listed.  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.  For the avoidance of doubt, this Section 3.6 shall not preclude any action taken without shareholder approval that is described in Section 4.2.

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, the maximum aggregate number of shares of Stock that may be issued under the Plan shall be seventeen million (17,000,000) less one share for every one share of Stock covered by an award granted under the Prior Plan after December 31, 2013 and prior to the Effective Date.  After the Effective Date, no awards may be granted under the Prior Plan.  Shares of Stock issued hereunder shall consist of authorized but unissued or reacquired shares of Stock or any combination thereof.  If (i) 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; or (ii) after December 31, 2013, an outstanding award under the Prior Plan (whenever granted) 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 under the Prior Plan 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 or stock shall again be available for issuance under the Plan (as of December 31, 2013 there were 6,194,819 shares of stock subject to outstanding awards under the Prior Plan).  Shares of Stock shall not be deemed to have been issued pursuant to the Plan (and shall again be available for issuance under the Plan) with respect to any portion of an Award (or, after December 31, 2013, an award under the Prior Plan) 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).  Upon the exercise of an SAR (or, after December 31, 2013, exercise of an SAR that was granted under the Prior Plan), the gross number of shares for which the SAR is exercised shall be deemed issued and shall not again be available for issuance under the Plan.  In the event that (i) any Option or other Award granted hereunder is exercised through the tendering of shares of Stock (either actually or by attestation) or by the withholding of shares by the Company, or (ii) withholding tax liabilities arising from such Award are satisfied by the tendering of shares of Stock (either actually or by attestation) or by the withholding of shares by the Company, then in each such case (other than in the case of such shares tendered or withheld in connection with the exercise of Options or SARs) the shares of Stock so tendered or withheld shall be added to the shares available for grant under the Plan on a one-for-one basis.  In the event that after December 31, 2013, (i) any option or award under the Prior Plan is exercised through the tendering of shares (either actually or by attestation) or by the withholding of shares by the Company, or (ii) withholding tax liabilities arising from such options or awards are satisfied by the tendering of shares (either actually or by attestation) or by the withholding of shares by the Company, then in each such case (other than in the case of such shares tendered or withheld in connection with the exercise of Options or SARs) the shares so tendered or withheld shall be added to the shares available for grant under the Plan on a one-for-one basis.

4.2Adjustments for Changes in Capital Structure.  Subject to any required action by the shareholders of the Company, Section 409A of the Code and Section 162(m) of the Code for Awards intended to comply with the "qualified performance-based compensation" exception thereunder, 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, 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, subject to Section 162(m) of the Code for Awards intended to qualify as "performance-based compensation" thereunder.  The adjustments determined by the Committee pursuant to this Section 4.2 shall be final, binding and conclusive.

4.3Substitute Awards.To the extent permitted under the rules of the applicable stock exchange on which the Stock is listed, Substitute Awards shall not reduce the shares of Stock authorized for grant under the Plan, nor shall Shares subject to a Substitute Award be added to the shares of Stock available for Awards under the Plan as provided above.  Additionally, subject to the rules of the applicable stock exchange on which the Stock is listed, in the event that a company acquired by the Company or any Subsidiary Corporation or with which the Company or any Subsidiary Corporation combines has shares available under a pre-existing plan approved by shareholders and not adopted in contemplation of such acquisition or combination, the shares available for grant pursuant to the terms of such pre-existing plan (as adjusted, to the extent appropriate, using the exchange ratio or other adjustment or valuation ratio or formula used in such acquisition or combination to determine the consideration payable to the holders of common stock of the entities party to such acquisition or combination) may be used for Awards under the Plan and shall not reduce the shares authorized for grant under the Plan (and shares subject to such Awards shall not be added to the shares available for Awards under the Plan as provided in the paragraphs above); provided that Awards using such available shares shall not be made after the date awards or grants could have been made under the terms of the pre-existing plan, absent the acquisition or combination, and shall only be made to individuals who were not Employees or Directors prior to such acquisition or combination.

5.Eligibility and Award Limitations.

5.1Persons Eligible for Awards.  Awards may be granted only to Employees, Consultants and Directors (including Non-employee 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 Non-employee Director Award may be granted only to a person who, at the time of grant, is a Non-employee Director.

5.2Participation.  Awards other than Non-employee Director Awards are granted solely at the discretion of the Committee.  Eligible persons may be granted more than one Award.  However, 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 ("ISO") 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 the number of shares set forth in the first sentence of Section 4.1 plus, to the extent allowable under Section 422 of the Code and the Treasury Regulations thereunder, any shares of Stock that again become available for issuance pursuant to the remaining provisions of Section 4.1.

(b)Section 162(m) Award Limits.  Subject to adjustment as provided in Section 4.2, no Participant may be granted (i) Options or Stock Appreciation Rights during any calendar year with respect to more than 800,000 shares of Stock in the aggregate, and (ii) during any calendar year one or more Restricted Stock Awards, Restricted Stock Unit Awards or Performance Share Awards that are intended to comply with the performance-based exception under Code Section 162(m) for more than 1,600,000 shares of Stock in the aggregate; provided that, for this purpose, such limit shall be applied based on the maximum number of shares of Stock that may be earned under the applicable Award(s).  During any calendar year no Participant may be granted Performance Units or other Awards that are intended to comply with the performance-based exception under Code Section 162(m) and are denominated in cash under which more than $20,000,000 may be earned in the aggregate.  Each of the limitations in this section shall be multiplied by two with respect to Awards granted to a Participant during the first calendar year in which the Participant commences employment with the Company and its Subsidiaries.  If an Award is cancelled, the cancelled Award shall continue to be counted toward the applicable limitation in this Section.

(c)Non-employee Director Award Limits.  No Non-employee Director shall be granted Awards (including Non-employee Director Awards) in any calendar year having an aggregate Grant Date value in excess of $400,000.  For this purpose, Restricted Stock Units, Restricted Stock Awards, Performance Awards, and other Awards shall be valued based on the Fair Market Value on the Grant Date of the maximum number of shares of Stock or dollars, as applicable, covered thereby and Options and SARs shall be valued using a Black-Scholes or other accepted valuation model, in each case, using reasonable assumptions.

5.5Dividends and Dividend Equivalents. Notwithstanding anything herein to the contrary, cash dividends, stock and any other property (other than cash) distributed as a dividend, a Dividend Equivalent or otherwise with respect to any Award that vests based on achievement of Performance Goals (a) shall either (i) not be paid or credited or (ii) be accumulated, (b) shall be subject to restrictions and risk of forfeiture to the same extent as the underlying Award with respect to which such cash, stock or other property has been distributed and (c) shall be paid after such restrictions and risk of forfeiture lapse in accordance with the terms of the applicable Award Agreement.

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 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 as a Substitute Award, except as would result in taxation under Section 409A or loss of ISO status.

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. Notwithstanding the foregoing, an Award Agreement may provide that if on the last day of the term of an Option the Fair Market Value of one share exceeds the option price per share, the Participant has not exercised the Option (or a tandem Stock Appreciation Right, if applicable) and the Option has not expired, the Option, to the extent vested, shall be deemed to have been exercised by the Participant on such day with payment made by withholding shares otherwise issuable in connection with the exercise of the Option.  In such event, the Company shall deliver to the Participant the number of shares for which the Option was deemed exercised, less the number of shares required to be withheld for the payment of the total purchase price and required withholding taxes; provided, however, any fractional share shall be settled in cash.

(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 15 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 earlier of the Option Expiration Date and the tenth anniversary of the date of grant of the Option.

(c)Extension if Exercise Prohibited by Law.  Notwithstanding the foregoing, in the event that on the last business day of the term of an Option (other than an Incentive Stock Option) the exercise of the Option is prohibited by applicable law, the term of the Option shall be extended for a period of thirty (30) days following the end of the legal prohibition.

7.Terms and Conditions of Non-employee Director Awards.

Non-employee 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.

The grant date for all Non-employee Director awards to be made under this Section 7 shall be the later of (1) the date on which the independent inspector of election certifies the results of the annual election of directors by shareholders of PG&E Corporation or (2) the date that this Plan becomes effective and grants can be made consistent with legal requirements; 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 January 1, 2015, shall be subject to the terms of Section 7 of the Prior Plan as in effect prior to the Effective Date, provided, however, that such grants shall be deemed made under this Plan.

7.1Grant of Restricted Stock Unit.

(a)Timing and Amount of Grant.  Each person who is a Non-employee Director on the Grant Date shall receive a grant of Restricted Stock Units with the number of Restricted Stock Units determined by dividing $140,000 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 Non-employee Director shall be credited to the director's Restricted Stock Unit account.  Each Restricted Stock Unit awarded to a Non-employee 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 Non-employee 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 Non-employee Director's Restricted Stock Unit account shall, to the extent vested, 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 Non-employee Director's death, (iii) the Non-employee Director's Disability (within the meaning of Section 409A of the Code), or (iv) the Non-employee Director's Separation from Service following a Change in Control.  However, commencing with Restricted Stock Units having a Grant Date in 2015, a Non-employee 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 Non-employee 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 Non-employee 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, to the extent vested, upon the occurrence of any of the events set forth in Section 7.1(c)(ii) through 7.1(c)(iv) prior to the elected settlement date (or commencement thereof in the case of settlement in 10 equal annual installments).  In the event that a Non-employee Director elects to have the Non-employee 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)(iv) occurs after commencement of such installments but prior to full settlement of the Non-employee 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 Non-employee Director.

(a)Forfeiture of Award.  If the Non-employee Director has a Separation from Service prior to the normal vesting date, all Restricted Stock Units credited to the Participant's account that have not vested in accordance with Section 7.2(b) or 7.3 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 Non-employee 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 Non-employee Director becomes "disabled," within the meaning of Section 409A of the Code or in the event of the Non-employee Director's death, all Restricted Stock Units credited to the Non-employee 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 amend this Section 7 or establish different terms and conditions pertaining to Non-employee Director Awards.

7.3Effect of Change in Control on Non-employee Director Awards. In the event a Non-employee Director ceases to be on the Board for any reason (other than resignation), following 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.

7.4Other Awards to Non-employee Directors.  Notwithstanding anything to the contrary set forth in this Plan, subject to Section 5.4(c) of the Plan, Non-employee Directors shall be eligible to receive all types of Awards under the Plan in addition to or instead of Non-employee Director Awards, as may be determined by the Board.

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 (other than in connection with Substitute Awards granted in accordance with Code Section 424(a)): (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.

(c)Extension if Exercise Prevented by Law.  Notwithstanding the foregoing, unless the Committee provides otherwise in the Award Agreement, if the exercise of an SAR within the applicable time periods is prevented by the provisions of Section 15 below, the SAR 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 SAR is exercisable, but in any event no later than the earlier of the date of expiration of the SAR's term (as set forth in the applicable Award Agreement) and the tenth anniversary of the date of grant of the SAR.

(d)Extension if Exercise Prohibited by Law.  Notwithstanding the foregoing, in the event that on the last business day of the term of an SAR the exercise of the SAR is prohibited by applicable law, the term shall be extended for a period of thirty (30) days following the end of the legal prohibition.

8.4Deemed Exercise of SARs.  An Award Agreement may provide that if on the last day of the term of an SAR the Fair Market Value of one share exceeds the grant price per share of the Stock Appreciation Right, the Participant has not exercised the SAR or the tandem Option (if applicable), and the SAR has not otherwise expired, the SAR, to the extent then vested, shall be deemed to have been exercised by the Participant on such day.  In such event, the Company shall make payment to the Participant in accordance with this Section, reduced by the number of shares (or cash) required for withholding taxes; any fractional share shall be settled in cash.

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.

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 or other performance conditions established by the Committee.  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) for Awards intended to comply with the "qualified performance-based compensation" exception under Section 162(m) of the Code.

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 18.  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, Section 5.5, 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.

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 to the extent required under Section 162(m).  Notwithstanding the foregoing, Awards that are not intended to comply with the "qualified performance-based compensation" exception under Section 162(m) may be subject to such other terms and conditions (which may be different from the terms and conditions set forth in this Section 10) as shall be determined by the Committee in its sole discretion.

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 for Awards intended to comply with the "qualified performance-based compensation" exception under Section 162(m) shall not be changed during the Performance Period, except as would result in the exercise of negative discretion by the Committee to reduce the amount of the Award otherwise payable as permitted under Section 162(m).  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, or may be based upon performance relative to performance of other companies or upon comparisons of any of the indicators of performance relative to performance of other companies.  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; (xxxix) core earnings; or (xxxx) operational performance.

(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 (or such shorter period set forth in an Award Agreement), 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 no later than the 15^th day of the third month following the completion of such Performance Period (or such shorter period set forth in an Award Agreement).

(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 (but not increase) 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 (or such shorter period set forth in an Award Agreement), 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 credited in connection with Performance Shares shall be subject to Section 5.5 of the Plan.  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 an adjustment described in Section 4.2, the adjusted Performance Share Award 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 termination of the Participant's Service for other reasons, the Committee, in its sole discretion, may waive the automatic forfeiture of all or any portion of any such Award, to the extent consistent with the preservation of the tax deductibility of awards pursuant to Section 162(m) of the Code.

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) for Awards intended to comply with the "qualified performance-based compensation" exception under Section 162(m).

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 and set forth in the Award Agreement.  In the event of an adjustment as described in Section 4.2, the Participant's adjusted Restricted Stock Unit Award 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, provided that Restricted Stock Units may be settled in cash, shares of Stock, or a combination thereof as determined by the Committee and set forth in the Award Agreement.  Notwithstanding the foregoing, if permitted by the Committee and set forth in the Award Agreement and subject to the restrictions of Section 409A of the Code, 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.

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)Subject to the restrictions of Section 409A of the Code, Participants designated by the Committee who are Insiders or otherwise among a select group of management or 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)Subject to the restrictions of Section 409A of the Code, Participants designated by the Committee who are Insiders or otherwise among a select group of management or 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 or shall not be subject to vesting conditions, as determined by the Committee.

(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, the Committee, in its discretion, may provide in the applicable Award Agreement 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 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.  Except as otherwise set forth in the applicable Award Agreement, 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. 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.

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.  Such awards may be evidenced by Award Agreements in such form as the Committee shall from time to time establish.

14.Change in Control.

14.1Effect of Change in Control.  Except as set forth in an applicable Award Agreement, 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 Awards or substitute for such Awards substantially equivalent Awards covering the Acquiror's stock.  Except as set forth in an applicable Award Agreement, any such Awards which are neither assumed, continued, or substituted by the Acquiror in connection with the Change in Control nor exercised (if applicable) as of the Change in Control shall, contingent on the Change in Control, become fully vested, and Options and SARs become exercisable immediately prior to the Change in Control.  Except as set forth in an applicable Award Agreement, Awards which are assumed or continued in connection with a Change in Control shall be subject to such additional accelerated vesting and/or exercisability, or lapse of restrictions in connection with the Participant's termination of Service in connection with the Change in Control as the Committee or Board may determine, if any.

14.2Non-employee Director Awards.  Notwithstanding the foregoing, Non-employee 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 unless 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.  Notwithstanding the foregoing, 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 to the extent required to avoid adverse accounting or other consequences to the Company or Participant.

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, (c) no amendment to Section 5.4(b) or 5.4(c), and (d) 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 and may do so without the approval of the Company's shareholders.  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.  A Participant's rights, if any, in respect of or in connection with any Award is derived solely from the discretionary decision of the Company to permit the individual to participate in the Plan and to benefit from a discretionary Award.  By accepting an Award under the Plan, a Participant expressly acknowledges that there is no obligation on the part of the Company to continue the Plan and/or grant any additional Awards.  Any Award granted hereunder is not intended to be compensation of a continuing or recurring nature, or part of a Participant's normal or expected compensation, and in no way represents any portion of a Participant's salary, compensation, or other remuneration for purposes of pension benefits, severance, redundancy, resignation or any other purpose.  The Company and its Parent Corporations and Subsidiary Corporations and Affiliates reserve the right to terminate the Service of any person at any time, and for any reason, subject to applicable laws and such person's written employee agreement (if any), and such terminated person shall be deemed irrevocably to have waived any claim to damages or specific performance for breach of contract or dismissal, compensation for loss of office, tort or otherwise with respect to the Plan or any outstanding Award that is forfeited and/or is terminated by its terms or to any future Award.

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 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 (i) 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 and any undelayed payments will be paid in accordance with their normal terms.

18.11Restrictions on Transfer.  No Award and no shares of Stock that have not been issued or as to which any applicable restriction, performance or deferral period has not lapsed, may be sold, assigned, transferred, pledged or otherwise encumbered, other than by will or the laws of decent and distribution, and such Award may be exercised during the life of the Participant only by the Participant or the Participant's guardian or legal representative.  Notwithstanding the foregoing, to the extent permitted by the Committee, in its discretion, and set forth in the applicable Award Agreement, an Award shall be assignable or transferrable to a "family member" or other permitted transferee to the extent covered under Form S-8 Registration Statement under the Securities Act.

PLAN HISTORY AND NOTES TO COMPANY

February 19, 2014	Board adopts Plan with a reserve of 17 million shares, less one share for every one share of Stock covered by an award granted under the Prior Plan after December 31, 2013 and prior to the Effective Date.
May 12, 2014	Shareholders approve Plan.  Plan Effective Date
January 1, 2016	The value of annual LTIP awards to non-employee directors increased to $140,000 from $105,000.

1. Establishment, Purpose and Term of Plan1

1.1 Establishment1

1.2 Purpose1

1.3 Term of Plan1

2. Definitions and Construction1

2.1 Definitions1

2.2 Construction7

3. Administration8

3.1 Administration by the Committee8

3.2 Authority of Officers8

3.3 Administration with Respect to Insiders8

3.4 Committee Complying with Section 162(m)8

3.5 Powers of the Committee8

3.6 Option or SAR Repricing/Buyout10

3.7 Indemnification10

4. Shares Subject to Plan10

4.1 Maximum Number of Shares Issuable10

4.2 Adjustments for Changes in Capital Structure11

4.3 Substitute Awards12

5. Eligibility and Award Limitations12

5.1 Persons Eligible for Awards12

5.2 Participation12

5.3 Incentive Stock Option Limitations13

5.4 Award Limits13

5.5 Dividends and Dividend Equivalents14

6. Terms and Conditions of Options14

6.1 Exercise Price14

6.2 Exercisability and Term of Options14

6.3 Payment of Exercise Price15

6.4 Effect of Termination of Service16

7. Terms and Conditions of Non-employee Director Awards16

7.1 Grant of Restricted Stock Unit16

7.2 Effect of Termination of Service as a Non-employee Director17

7.3 Effect of Change in Control on Non-employee Director Awards18

7.4 Other Awards to Non-employee Directors18

8. Terms and Conditions of Stock Appreciation Rights18

8.1 Types of SARs Authorized18

8.2 Exercise Price18

8.3 Exercisability and Term of SARs19

8.4 Deemed Exercise of SARs19

8.5 Effect of Termination of Service19

9. Terms and Conditions of Restricted Stock Awards19

9.1 Types of Restricted Stock Awards Authorized20

9.2 Purchase Price20

9.3 Purchase Period20

9.4 Vesting and Restrictions on Transfer20

9.5 Voting Rights, Dividends and Distributions20

9.6 Effect of Termination of Service21

10. Terms and Conditions of Performance Awards21

10.1 Types of Performance Awards Authorized21

10.2 Initial Value of Performance Shares and Performance Units21

10.3 Establishment of Performance Period, Performance Goals and Performance Award Formula21

10.4 Measurement of Performance Goals22

10.5 Settlement of Performance Awards23

10.6 Voting Rights, Dividend Equivalent Rights and Distributions23

10.7 Effect of Termination of Service24

11. Terms and Conditions of Restricted Stock Unit Awards24

11.1 Grant of Restricted Stock Unit Awards24

11.2 Vesting25

11.3 Voting Rights, Dividend Equivalent Rights and Distributions25

11.4 Effect of Termination of Service25

11.5 Settlement of Restricted Stock Unit Awards25

12. Deferred Compensation Awards26

12.1 Establishment of Deferred Compensation Award Programs26

12.2 Terms and Conditions of Deferred Compensation Awards26

13. Other Stock-Based Awards27

14. Change in Control27

14.1 Effect of Change in Control27

14.2 Non-employee Director Awards28

15. Compliance with Securities Law28

16. Tax Withholding28

16.1 Tax Withholding in General28

16.2 Withholding in Shares28

17. Amendment or Termination of Plan29

18. Miscellaneous Provisions29

18.1 Repurchase Rights29

18.2 Provision of Information29

18.3 Rights as Employee, Consultant or Director29

18.4 Rights as a Shareholder30

18.5 Fractional Shares30

18.6 Severability30

18.7 Beneficiary Designation30

18.8 Unfunded Obligation30

18.9 Choice of Law31

18.10 Section 409A of the Code31

18.11 Restrictions on Transfer31

EX-12.01

EXHIBIT 12.1PACIFIC GAS AND ELECTRIC COMPANYCOMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Year Ended December 31,
	2015			2014		2013		2012		2011
Earnings:
Net income	$	862		$	1,433	$	866	$	811	$	845
Income tax provision		(19	)		384		326		298		480
Fixed charges		1,260			1,176		971		891		880
Total earnings	$	2,103		$	2,993	$	2,163	$	2,000	$	2,205
Fixed charges:
Interest on short-term borrowings and    long-term debt, net	$	1,208		$	1,125	$	917	$	834	$	824
Interest on capital leases		4			6		7		9		16
AFUDC debt		48			45		47		48		40
Total fixed charges	$	1,260		$	1,176	$	971	$	891	$	880
Ratios of earnings to fixed charges		1.67			2.55		2.23		2.24		2.51

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 12.2PACIFIC GAS AND ELECTRIC COMPANYCOMPUTATION OF RATIOS OF EARNINGS TO COMBINEDFIXED CHARGES AND PREFERRED STOCK DIVIDENDS

	Year Ended December 31,
	2015			2014		2013		2012		2011
Earnings:
Net income	$	862		$	1,433	$	866	$	811	$	845
Income tax provision		(19	)		384		326		298		480
Fixed charges		1,260			1,176		971		891		880
Total earnings	$	2,103		$	2,993	$	2,163	$	2,000	$	2,205
Fixed charges:
Interest on short-term borrowings and
long-term debt, net	$	1,208		$	1,125	$	917	$	834	$	824
Interest on capital leases		4			6		7		9		16
AFUDC debt		48			45		47		48		40
Total fixed charges	$	1,260		$	1,176	$	971	$	891	$	880
Preferred stock dividends:
Tax deductible dividends	$	9		$	9	$	9	$	9	$	9
Pre-tax earnings required to cover non-tax
deductible preferred stock dividend
requirements		5			6		7		7		8
Total preferred stock dividends		14			15		16		16		17
Total combined fixed charges and
preferred stock dividends	$	1,274		$	1,191	$	987	$	907	$	897
Ratios of earnings to combined fixed charges
and preferred stock dividends		1.65			2.51		2.19		2.21		2.46

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,
	2015			2014			2013			2012			2011
Earnings:
Net income	$	888		$	1,450		$	828		$	830		$	858
Income tax provision		(27	)		345			268			237			440
Fixed charges		1,284			1,206			1,012			931			919
Pre-tax earnings required to cover the
preferred stock dividend of consolidated
subsidiaries		(14	)		(15	)		(16	)		(15	)		(17	)
Total earnings	$	2,131		$	2,986		$	2,092		$	1,983		$	2,200
Fixed charges:
Interest on short-term borrowings and
long-term debt, net	$	1,218		$	1,140		$	942		$	859		$	846
Interest on capital leases		4			6			7			9			16
AFUDC debt		48			45			47			48			40
Pre-tax earnings required to cover the
preferred stock dividend of consolidated		14			15			16			15			17
Total fixed charges	$	1,284		$	1,206		$	1,012		$	931		$	919
Ratios of earnings to fixed charges		1.66			2.48			2.07			2.13			2.39

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-21

Exhibit 21

Significant Subsidiaries

Parent of Significant Subsidiary	Name of Significant Subsidiary	Jurisdiction of Formation of Subsidiary	Names under which Significant Subsidiary does business
PG&E Corporation	Pacific Gas and Electric Company	CA	Pacific Gas and Electric Company PG&E
Pacific Gas and Electric Company	None

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statements No. 333-193880 on Form S-3, 333-144498 on Form S-3D, and 333-129422, 333-176090, 333-195902 and 333-206457 on Form S-8 of PG&E Corporation and Registration Statement No. 333-193879 on Form S-3 of Pacific Gas and Electric Company of our reports dated February 18, 2016, relating to the consolidated financial statements of PG&E Corporation and subsidiaries  ("the Company") and Pacific Gas and Electric Company and subsidiaries (the "Utility"), the consolidated financial statement schedules of the Company and 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, 2015.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 18, 2016

EX-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, and ERIC A. MONTIZAMBERT, 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, 2015 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 2nd day of February, 2016.

/s/ LEWIS CHEW	/s/ RICHARD A. MESERVE
Lewis Chew	Richard A. Meserve
/s/ ANTHONY F. EARLEY, JR.	/s/ FORREST E. MILLER
Anthony F. Earley, Jr.	Forrest E. Miller
/s/ FRED J. FOWLER	/s/ ROSENDO G. PARRA
Fred J. Fowler	Rosendo G. Parra
/s/ MARYELLEN C. HERRINGER	/s/ BARBARA L. RAMBO
Maryellen C. Herringer	Barbara L. Rambo
/s/ RICHARD C. KELLY	/s/ ANNE SHEN SMITH
Richard C. Kelly	Anne Shen Smith
/s/ ROGER H. KIMMEL	/s/ BARRY LAWSON WILLIAMS
Roger H. Kimmel	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, and ERIC A. MONTIZAMBERT, 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, 2015 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 2nd day of February, 2016.

/s/ LEWIS CHEW	/s/ FORREST E. MILLER
Lewis Chew	Forrest E. Miller
/s/ ANTHONY F. EARLEY, JR	/s/ ROSENDO G. PARRA
Anthony F. Earley, Jr.	Rosendo G. Parra
/s/ FRED J. FOWLER	/s/ BARBARA L. RAMBO
Fred J. Fowler	Barbara L. Rambo
/s/ MARYELLEN C. HERRINGER	/s/ ANNE SHEN SMITH
Maryellen C. Herringer	Anne Shen Smith
/s/ RICHARD C. KELLY	/s/ NICKOLAS STAVROPOULOS
Richard C. Kelly	Nickolas Stavropoulos
/s/ ROGER H. KIMMEL	/s/ BARRY LAWSON WILLIAMS
Roger H. Kimmel	Barry Lawson Williams
/s/ RICHARD A. MESERVE	/s/ GEISHA J. WILLIAMS
Richard A. Meserve	Geisha J. Williams

EX-31.01

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, 2015 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 18, 2016	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, Jason P. Wells, certify that:

1. I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2015 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 18, 2016	JASON P. WELLS
	Jason P. Wells
	Senior Vice President and Chief Financial Officer

EX-31.02

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Nickolas Stavropoulos, certify that:

1. I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2015 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 officers 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 officers 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 18, 2016	NICKOLAS STAVROPOULOS
	Nickolas Stavropoulos
	President, Gas

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Geisha J. Williams, certify that:

1. I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2015 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 officers 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 officers 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 18, 2016	GEISHA J. WILLIAMS
	Geisha J. Williams
	President, Electric

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, 2015 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 officers 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 officers 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 18, 2016	DINYAR B. MISTRY
	Dinyar B. Mistry
	Vice President, Chief Financial Officer, and Controller

EX-32.01

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICERPURSUANT 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, 2015 ("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 18, 2016

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICERPURSUANT 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, 2015 ("Form 10-K"), I, Jason P. Wells, 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.

JASON P. WELLS

JASON P. WELLS

Senior Vice President and

Chief Financial Officer

February 18, 2016

 

EX-32.02

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICERPURSUANT 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, 2015 ("Form 10-K"), I, Nickolas Stavropoulos, President, Gas 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.

NICKOLAS STAVROPOULOS

NICKOLAS STAVROPOULOS

President, Gas

February 18, 2016

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICERPURSUANT 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, 2015 ("Form 10-K"), I, Geisha J. Williams, President, Electric 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.

GEISHA J. WILLIAMS

GEISHA J. WILLIAMS

President, Electric

February 18, 2016

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICERPURSUANT 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, 2015 ("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 18, 2016

XML

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 12, 2016	Jun. 30, 2015
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Entity Filer Category	Large Accelerated Filer
Entity Registrant Name	PG&E CORP
Entity Central Index Key	0001004980
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2015
Entity Current Reporting Status	Yes
Trading Symbol	PCG
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 23,628
Entity Common Stock, Shares Outstanding		492,830,471
Pacific Gas And Electric Company [Member]
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Entity Filer Category	Non-accelerated Filer
Entity Registrant Name	PACIFIC GAS & ELECTRIC CO
Entity Central Index Key	0000075488
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2015
Entity Current Reporting Status	Yes
Trading Symbol	PCG
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Common Stock, Shares Outstanding		264,374,809

XML

Consolidated Statements Of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Revenues
Electric	$ 13,657	$ 13,658	$ 12,494
Natural gas	3,176	3,432	3,104
Total operating revenues	16,833	17,090	15,598
Operating Expenses
Cost of electricity	5,099	5,615	5,016
Cost of natural gas	663	954	968
Operating and maintenance	6,951	5,638	5,775
Depreciation, amortization, and decommissioning	2,612	2,433	2,077
Total operating expenses	15,325	14,640	13,836
Operating Income	1,508	2,450	1,762
Interest income	9	9	9
Interest expense	(773)	(734)	(715)
Other income (expense)	117	70	40
Income Before Income Taxes	861	1,795	1,096
Income tax benefit	(27)	345	268
Net Income	888	1,450	828
Preferred stock dividend requirement of subsidiary	14	14	14
Income Available for Common Shareholders	$ 874	$ 1,436	$ 814
Weighted Average Common Shares Outstanding, Basic	484	468	444
Weighted Average Common Shares Outstanding, Diluted	487	470	445
Net earnings per common share, basic	$ 1.81	$ 3.07	$ 1.83
Net Earnings Per Common Share, Diluted	$ 1.79	$ 3.06	$ 1.83
Pacific Gas And Electric Company [Member]
Operating Revenues
Electric	$ 13,657	$ 13,656	$ 12,489
Natural gas	3,176	3,432	3,104
Total operating revenues	16,833	17,088	15,593
Operating Expenses
Cost of electricity	5,099	5,615	5,016
Cost of natural gas	663	954	968
Operating and maintenance	6,949	5,635	5,742
Depreciation, amortization, and decommissioning	2,611	2,432	2,077
Total operating expenses	15,322	14,636	13,803
Operating Income	1,511	2,452	1,790
Interest income	8	8	8
Interest expense	(763)	(720)	(690)
Other income (expense)	87	77	84
Income Before Income Taxes	843	1,817	1,192
Income tax benefit	(19)	384	326
Net Income	862	1,433	866
Preferred stock dividend requirement	14	14	14
Income Available for Common Shareholders	$ 848	$ 1,419	$ 852

XML

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net income	$ 888	$ 1,450	$ 828
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (related to PG&E Corporation net of income tax of $0, $10 and $80 and related to the Utility of $1, $6, and $75, at respective dates)	(1)	(14)	113
Net change in investments (net of taxes $12, $17, and $26, at respective dates)	(17)	(25)	38
Total other comprehensive income (loss)	(18)	(39)	151
Comprehensive Income	870	1,411	979
Preferred stock dividend requirement of subsidiary	14	14	14
Comprehensive Income Attributable to Common Shareholders	856	1,397	965
Pacific Gas And Electric Company [Member]
Net income	862	1,433	866
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (related to PG&E Corporation net of income tax of $0, $10 and $80 and related to the Utility of $1, $6, and $75, at respective dates)	(2)	(8)	106
Total other comprehensive income (loss)	(2)	(8)	106
Comprehensive Income	$ 860	$ 1,425	$ 972

XML

Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension and other postretirement benefit plans obligations tax	$ 0	$ 10	$ 80
Change in investments tax	12	17	26
Pacific Gas And Electric Company [Member]
Pension and other postretirement benefit plans obligations tax	$ 1	$ 6	$ 75

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 123	$ 151
Restricted cash	234	298
Accounts receivable
Customers (net of allowance for doubtful accounts of $54 and $66 at respective dates)	1,106	960
Accrued unbilled revenue	855	776
Regulatory balancing accounts	1,760	2,266
Other	286	377
Regulatory assets	517	444
Inventories
Gas stored underground and fuel oil	126	172
Materials and supplies	313	304
Income taxes receivable	155	198
Other	347	443
Total current assets	5,822	6,389
Property, Plant, and Equipment
Electric	48,532	45,162
Gas	16,749	15,678
Construction work in progress	2,059	2,220
Other	2	2
Total property, plant, and equipment	67,342	63,062
Accumulated depreciation	(20,619)	(19,121)
Net property, plant, and equipment	46,723	43,941
Other Noncurrent Assets
Regulatory assets	7,029	6,322
Nuclear decommissioning trusts	2,470	2,421
Income taxes receivable	135	91
Other	1,160	963
Total other noncurrent assets	10,794	9,797
TOTAL ASSETS	63,339	60,127
Current Liabilities
Short-term borrowings	1,019	633
Long-term debt, classified as current	160	0
Accounts payable
Trade creditors	1,414	1,244
Regulatory balancing accounts	715	1,090
Other	398	476
Disputed claims and customer refunds	454	434
Interest payable	206	197
Other	1,997	1,846
Total current liabilities	6,363	5,920
Noncurrent Liabilities
Long-term debt	16,030	15,050
Regulatory liabilities	6,321	6,290
Pension and other postretirement benefits	2,622	2,561
Asset retirement obligations	3,643	3,575
Deferred income taxes	9,206	8,513
Other	2,326	2,218
Total noncurrent liabilities	$ 40,148	$ 38,207
Commitments and Contingencies (Note 13)
Shareholders' Equity
Common stock	$ 11,282	$ 10,421
Reinvested earnings	5,301	5,316
Accumulated other comprehensive(loss)income	(7)	11
Total shareholders' equity	16,576	15,748
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	16,828	16,000
TOTAL LIABILITIES AND EQUITY	63,339	60,127
Pacific Gas And Electric Company [Member]
Current Assets
Cash and cash equivalents	59	55
Restricted cash	234	298
Accounts receivable
Customers (net of allowance for doubtful accounts of $54 and $66 at respective dates)	1,106	960
Accrued unbilled revenue	855	776
Regulatory balancing accounts	1,760	2,266
Other	284	375
Regulatory assets	517	444
Inventories
Gas stored underground and fuel oil	126	172
Materials and supplies	313	304
Income taxes receivable	130	168
Other	346	409
Total current assets	5,730	6,227
Property, Plant, and Equipment
Electric	48,532	45,162
Gas	16,749	15,678
Construction work in progress	2,059	2,220
Total property, plant, and equipment	67,340	63,060
Accumulated depreciation	(20,617)	(19,120)
Net property, plant, and equipment	46,723	43,940
Other Noncurrent Assets
Regulatory assets	7,029	6,322
Nuclear decommissioning trusts	2,470	2,421
Income taxes receivable	135	91
Other	1,053	864
Total other noncurrent assets	10,687	9,698
TOTAL ASSETS	63,140	59,865
Current Liabilities
Short-term borrowings	1,019	633
Long-term debt, classified as current	160	0
Accounts payable
Trade creditors	1,414	1,243
Regulatory balancing accounts	715	1,090
Other	418	444
Disputed claims and customer refunds	454	434
Interest payable	203	195
Other	1,750	1,604
Total current liabilities	6,133	5,643
Noncurrent Liabilities
Long-term debt	15,680	14,700
Regulatory liabilities	6,321	6,290
Pension and other postretirement benefits	2,534	2,477
Asset retirement obligations	3,643	3,575
Deferred income taxes	9,487	8,773
Other	2,282	2,178
Total noncurrent liabilities	$ 39,947	$ 37,993
Commitments and Contingencies (Note 13)
Shareholders' Equity
Preferred stock	$ 258	$ 258
Common stock	1,322	1,322
Additional paid-in capital	7,215	6,514
Reinvested earnings	8,262	8,130
Accumulated other comprehensive(loss)income	3	5
Total shareholders' equity	17,060	16,229
TOTAL LIABILITIES AND EQUITY	$ 63,140	$ 59,865

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Allowance for doubtful accounts	$ 54	$ 66
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	800,000,000	800,000,000
Common stock, shares outstanding	492,025,443	475,913,404
Pacific Gas And Electric Company [Member]
Allowance for doubtful accounts	$ 54	$ 66
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

XML

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows from Operating Activities
Net income	$ 888	$ 1,450	$ 828
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,612	2,433	2,077
Allowance for equity funds used during construction	(107)	(100)	(101)
Deferred income taxes and tax credits, net	693	690	1,075
Disallowed capital expenditures	407	116	196
Other	326	286	355
Effect of changes in operating assets and liabilities:
Accounts receivable	(177)	13	(152)
Inventories	37	(22)	(10)
Accounts payable	(55)	(61)	113
Income taxes receivable/payable	43	376	(363)
Other current assets and liabilities	(315)	205	(469)
Regulatory assets, liabilities, and balancing accounts, net	(244)	(1,642)	(202)
Other noncurrent assets and liabilities	(355)	(67)	80
Net cash provided by operating activities	3,753	3,677	3,427
Cash Flows from Investing Activities
Capital expenditures	(5,173)	(4,833)	(5,207)
Decrease in restricted cash	64	3	29
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,268	1,336	1,619
Purchases of nuclear decommissioning trust investments	(1,392)	(1,334)	(1,604)
Other	22	114	56
Net cash used in investing activities	(5,211)	(4,714)	(5,107)
Cash Flows from Financing Activities
Borrowings (repayments) under revolving credit facilities	0	(260)	140
Net issuances (repayments) of commercial paper, net of discount of $3, $2, and $2 at respective dates	683	(583)	542
Proceeds from issuance of short-term debt, net of issuance costs	0	300	0
Short-term debt matured	(300)	0	0
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of (for PG&E Corporaiton $27, $17, and $18 and for the Utility $27, $14, and $18, at respective dates)	1,123	2,308	1,532
Repayments of long-term debt	0	(889)	(861)
Common stock issued	780	802	1,045
Common stock dividends paid	(856)	(828)	(782)
Other	0	42	(41)
Net cash provided by (used in) financing activities	1,430	892	1,575
Net change in cash and cash equivalents	(28)	(145)	(105)
Cash and cash equivalents at January 1	151	296	401
Cash and cash equivalents at December 31	123	151	296
Cash received (paid) for:
Interest, net of amounts capitalized	(684)	(633)	(623)
Income taxes, net	77	501	(41)
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	224	217	208
Capital expenditures financed through accounts payable	440	339	322
Noncash common stock issuances	21	21	22
Terminated Capital Leases	0	71	0
Pacific Gas And Electric Company [Member]
Cash Flows from Operating Activities
Net income	862	1,433	866
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,611	2,432	2,077
Allowance for equity funds used during construction	(107)	(100)	(101)
Deferred income taxes and tax credits, net	714	731	1,103
Disallowed capital expenditures	407	116	196
Other	263	226	299
Effect of changes in operating assets and liabilities:
Accounts receivable	(177)	16	(152)
Inventories	37	(22)	(10)
Accounts payable	(2)	(55)	99
Income taxes receivable/payable	38	395	(377)
Other current assets and liabilities	(342)	155	(404)
Regulatory assets, liabilities, and balancing accounts, net	(244)	(1,642)	(202)
Other noncurrent assets and liabilities	(340)	(66)	22
Net cash provided by operating activities	3,720	3,619	3,416
Cash Flows from Investing Activities
Capital expenditures	(5,173)	(4,833)	(5,207)
Decrease in restricted cash	64	3	29
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,268	1,336	1,619
Purchases of nuclear decommissioning trust investments	(1,392)	(1,334)	(1,604)
Other	22	29	21
Net cash used in investing activities	(5,211)	(4,799)	(5,142)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $3, $2, and $2 at respective dates	683	(583)	542
Proceeds from issuance of short-term debt, net of issuance costs	0	300	0
Short-term debt matured	(300)	0	0
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of (for PG&E Corporaiton $27, $17, and $18 and for the Utility $27, $14, and $18, at respective dates)	1,123	1,961	1,532
Repayments of long-term debt	0	(539)	(861)
Preferred stock dividends paid	(14)	(14)	(14)
Common stock dividends paid	(716)	(716)	(716)
Equity contribution from PG&E Corporation	705	705	1,140
Other	14	56	(26)
Net cash provided by (used in) financing activities	1,495	1,170	1,597
Net change in cash and cash equivalents	4	(10)	(129)
Cash and cash equivalents at January 1	55	65	194
Cash and cash equivalents at December 31	59	55	65
Cash received (paid) for:
Interest, net of amounts capitalized	(675)	(618)	(600)
Income taxes, net	77	500	(62)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	440	339	322
Terminated Capital Leases	$ 0	$ 71	$ 0

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Consolidated Statements Of Cash Flows (Parenthetical) - Pacific Gas And Electric Company [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows from Financing Activities
Net issuances of commercial paper, discount	$ 3	$ 2	$ 2
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs	$ 27	$ 14	$ 18

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Consolidated Statements Of Equity - USD ($) $ in Millions	Total	Pacific Gas And Electric Company [Member]	Common Stock Shares [Member]	Common Stock Shares [Member] Pacific Gas And Electric Company [Member]	Preferred Stock [Member] Pacific Gas And Electric Company [Member]	Common Stock Amount [Member]	Additional Paid-In Capital [Member] Pacific Gas And Electric Company [Member]	Reinvested Earnings [Member]	Reinvested Earnings [Member] Pacific Gas And Electric Company [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Accumulated Other Comprehensive Income (Loss) [Member] Pacific Gas And Electric Company [Member]	Total Shareholders' Equity [Member]	Total Shareholders' Equity [Member] Pacific Gas And Electric Company [Member]	Noncontrolling Interest - Preferred Stock Of Subsidiary [Member]
Balance at Dec. 31, 2012	$ 13,326			$ 1,322	$ 258	$ 8,428	$ 4,682	$ 4,747	$ 7,291	$ (101)	$ (93)	$ 13,074	$ 13,460	$ 252
Balance, in shares at Dec. 31, 2012			430,718,293
Net income	828	$ 866						828	866			828	866
Other comprehensive income (loss)	151	106								151	106	151	106
Equity contribution from PG&E Corporation		1,140					1,140						1,140
Common stock issued, net	1,067					1,067						1,067
Common stock issued, net, shares			25,952,131
Stock-based compensation amortization	56					56						56
Tax expense from employee stock plans	(1)					(1)	(1)					(1)	(1)
Common stock dividends declared	(819)							(819)	(716)			(819)	(716)
Preferred stock dividend									(14)				(14)
Preferred stock dividend requirement of subsidiary	(14)							(14)				(14)
Balance at Dec. 31, 2013	14,594			1,322	258	9,550	5,821	4,742	7,427	50	13	14,342	14,841	252
Balance, in shares at Dec. 31, 2013			456,670,424
Net income	1,450	1,433						1,450	1,433			1,450	1,433
Other comprehensive income (loss)	(39)	(8)								(39)	(8)	(39)	(8)
Equity contribution from PG&E Corporation		$ 705					705						705
Common stock issued, net	823					823						823
Common stock issued, net, shares			19,242,980
Stock-based compensation amortization	65					65						65
Tax expense from employee stock plans	(17)					(17)	(12)					(17)	(12)
Common stock dividends declared	(862)							(862)	(716)			(862)	(716)
Preferred stock dividend									(14)				(14)
Preferred stock dividend requirement of subsidiary	(14)							(14)				(14)
Balance at Dec. 31, 2014	$ 16,000			1,322	258	10,421	6,514	5,316	8,130	11	5	15,748	16,229	252
Balance, in shares at Dec. 31, 2014	475,913,404	264,374,809	475,913,404
Net income	$ 888	$ 862						888	862			888	862
Other comprehensive income (loss)	(18)	(2)								(18)	(2)	(18)	(2)
Equity contribution from PG&E Corporation		$ 705					705						705
Common stock issued, net	801					801						801
Common stock issued, net, shares			16,112,039
Stock-based compensation amortization	66					66						66
Tax expense from employee stock plans	(6)					(6)	(4)					(6)	(4)
Common stock dividends declared	(889)							(889)	(716)			(889)	(716)
Preferred stock dividend									(14)				(14)
Preferred stock dividend requirement of subsidiary	(14)							(14)				(14)
Balance at Dec. 31, 2015	$ 16,828			$ 1,322	$ 258	$ 11,282	$ 7,215	$ 5,301	$ 8,262	$ (7)	$ 3	$ 16,576	$ 17,060	$ 252
Balance, in shares at Dec. 31, 2015	492,025,443	264,374,809	492,025,443

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Organization And Basis Of Presentation

12 Months Ended

Dec. 31, 2015

Organization And Basis Of Presentation

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, 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 CPUC and the FERC.  In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. 

This is a combined annual report of 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 in consolidation.  The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility.  PG&E Corporation and the Utility assessfinancial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).

The accompanying consolidated financial statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K.  The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, environmental remediation liabilities, AROs, 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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Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Summary Of Significant Accounting Policies

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Regulation and Regulated Operations

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service.  The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  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.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.  In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income.  (See “Revenue Recognition” below.)

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.  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.

Revenue Recognition

The Utility recognizes revenues when electricity and natural gas services are delivered.  The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements.

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, 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 that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, revenue is recognized ratably over the year.

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. In general, 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 periodic (often annual) TO 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.

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.  (See “Resolution of Remaining Chapter 11 Disputed Claims” in Note 13 below.)

Allowance for Doubtful Accounts Receivable

PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer accounts receivable at estimated net realizable value.  The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.

Inventories

Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.

Emission Allowances

The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.

Property, Plant, and Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  (See “AFUDC” below.)  The Utility’s total 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)	2015		2014
Electricity generating facilities (1)	5 to 100	$	9,860		$	9,374
Electricity distribution facilities	15 to 55		28,476			26,633
Electricity transmission facilities	15 to 75		10,196			9,155
Natural gas distribution facilities	5 to 60		10,397			9,741
Natural gas transportation and storage facilities	5 to 65		6,352			5,937
Construction work in progress			2,059			2,220
Total property, plant, and equipment			67,340			63,060
Accumulated depreciation			(20,617)			(19,120)
Net property, plant, and equipment		$	46,723		$	43,940

(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 13 below.)

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 balance 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 3.80% in 2015, 3.77% in 2014, and 3.51% in 2013.  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 represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service 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 related to debt and equity, respectively, of $48 million and $107 million during 2015, $45 million and $100 million during 2014, and $47 million and $101 million during 2013.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2015 and 2014, including nuclear decommissioning obligations:

(in millions)		2015		2014
ARO liability at beginning of year	$	3,575	$	3,538
Revision in estimated cash flows		13		(16)
Accretion		169		163
Liabilities settled		(114)		(110)
ARO liability at end of year	$	3,643	$	3,575

The Utility has not recorded a liability related to certain ARO’s for assets that are expected to operate in perpetuity.  As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made.  As such, ARO liabilities are not recorded for retirement activities associated with substations, photovoltaic facilities, and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration or land to the conditions under certain agreements.

Nuclear Decommissioning Obligation

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.

The Utility adjusts its nuclear decommissioning obligation to reflect changes in the estimated costs of decommissioning its nuclear power facilities and records this as an adjustment to the ARO liability on its Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued was $2.5 billion at December 31, 2015 and 2014.  The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $3.5 billion at December 31, 2015 and 2014 (or $6.1 billion in future dollars). These estimates are based on the 2012 decommissioning cost studies, prepared in accordance with CPUC requirements.

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge 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.  The Utility recorded charges of $407 million in 2015 for estimated capital spending that is probable of disallowance related to the Penalty Decision and $116 million and $196 million in 2014 and 2013, respectively, for PSEP capital costs that are expected to exceed the CPUC’s authorized levels or that are specifically disallowed.  (See “Enforcement and Litigation Matters” in Note 13 below).

Nuclear Decommissioning Trusts

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one 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 by the trust is determined by specific identification.

Variable Interest Entities

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 that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate 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.  To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2015, it assessed 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, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities.  The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2015, it did not consolidate any of them.

Other Accounting Policies

For other accounting policies impacting PG&E Corporation’s and the Utility’s consolidated financial statements, see “Income Taxes” in Note 8, “Derivatives” in Note 9, “Fair Value Measurements” in Note 10, and “Contingencies and Commitments” in Note 13 of the Notes to the Consolidated Financial Statements.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2015 consisted of the following:

	Pension		Other			Other
(in millions, net of income tax)	Benefits		Benefits			Investments			Total
Beginning balance	$	(21)		$	15		$	17		$	11
Other comprehensive income before reclassifications:
Unrecognized net actuarial loss
(net of taxes of $51, $21, and $0, respectively)		(76)			(31)			-			(107)
Regulatory account transfer
(net of taxes of $51, $21, and $0, respectively)		73			31			-			104
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $7, $8, and $0, respectively) (1)		8			11			-			19
Amortization of net actuarial loss
(net of taxes of $4, $1, and $0, respectively) (1)		6			3			-			9
Regulatory account transfer
(net of taxes of $10, $9, and $0, respectively) (1)		(13)			(13)			-			(26)
Realized gain on investments
(net of taxes of $0, $0, and $12, respectively)		-			-			(17)			(17)
Net current period other comprehensive loss		(2)			1			(17)			(18)
Ending balance	$	(23)		$	16		$	-		$	(7)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2014 consisted of the following:

	Pension		Other			Other
(in millions, net of income tax)	Benefits		Benefits			Investments			Total
Beginning balance	$	(7)		$	15		$	42		$	50
Other comprehensive income before reclassifications:
Change in investments
(net of taxes of $0, $0, and $4, respectively)		-			-			5			5
Unrecognized net actuarial loss
(net of taxes of $404, $19, and $0, respectively)		(588)			(28)			-			(616)
Unrecognized prior service cost
(net of taxes of $0, $0, and $0, respectively)		1			-			-			1
Regulatory account transfer
(net of taxes of $394, $19, and $0, respectively)		573			28			-			601
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $8, $9, and $0, respectively) (1)		12			14			-			26
Amortization of net actuarial loss
(net of taxes of $1, $1, and $0, respectively) (1)		1			1			-			2
Regulatory account transfer
(net of taxes of $9, $10, and $0, respectively) (1)		(13)			(15)			-			(28)
Realized gain on investments
(net of taxes of $0, $0, and $20, respectively)		-			-			(30)			(30)
Net current period other comprehensive loss		(14)			-			(25)			(39)
Ending balance	$	(21)		$	15		$	17		$	11

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)

With the exception of other investments, there was no material difference between PG&E Corporation and the Utility for the information disclosed above.

New Accounting Pronouncements

Recognition and Measurement of Financial Assets and Financial Liabilities

InJanuary 2016, the FASB issued ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which amends guidance to help improve the recognition and measurement of financial instruments. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018.PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes, which amends existing guidance on the presentation of deferred income tax assets and liabilities. The amendments in the ASU require that all deferred tax liabilities and assets be classified as noncurrent on the balance sheet.  This ASU will be effective for PG&E Corporation and the Utility on January 1, 2017, with earlier adoption permitted.  PG&E Corporation and the Utility have implemented this standard as of the year ended December 31, 2015 on a prospective basis and the prior periods have not been retrospectively adjusted. 

Fair Value Measurement

In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which removes the requirement to categorize within the fair value hierarchy all investments measured using net asset value per share as a practical expedient.  The ASU became effective for PG&E Corporation and the Utility on January 1, 2016.  This standard will be adopted for related disclosures in the first quarter of 2016 and will not have an impact on the consolidated financial statements. 

Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued ASU No. 2015-05, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement, which adds guidance to help entities evaluate the accounting treatment for cloud computing arrangements.  The ASU became effective for PG&E Corporation and the Utility on January 1, 2016.  PG&E Corporation and the Utility have determined that this ASU will not impact their consolidated financial statements and related disclosures and will adopt this standard starting in the first quarter of 2016.

Presentation of Debt Issuance Costs

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which amends existing presentation of debt issuance costs.  PG&E Corporation and the Utility currently disclose debt issuance costs in current assets – other and noncurrent assets – other.The amendments in this ASU, that became effective for PG&E Corporation and the Utility on January 1, 2016, require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.  PG&E Corporation and the Utility will adopt this standard in the first quarter of 2016 and do not expect the reclassification to have a material impact on their consolidated financial statements. 

Revenue Recognition Standard

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, deferring the effective date of this amendment for PG&E Corporation and the Utility by one year to January 1, 2018, with early adoption permitted as of the original effective date of January 1, 2017.PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures.

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Regulatory Assets, Liabilities, And Balancing Accounts

12 Months Ended

Dec. 31, 2015

Regulatory Assets, Liabilities, And Balancing Accounts

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance at December 31,					Recovery
(in millions)	2015		2014			Period
Pension benefits (1)	$	2,414	$	2,347	Indefinitely (4)
Deferred income taxes (1)		3,054		2,390	47 years
Utility retained generation (2)		411		456	10 years
Environmental compliance costs (1)		748		717	32 years
Price risk management (1)		138		127	10 years
Electromechanical meters (3)		-		70	-
Unamortized loss, net of gain, on reacquired debt (1)		94		113	11 years
Other		170		102	Various
Total long-term regulatory assets	$	7,029	$	6,322

(1) Represents the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP.

(2) 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, 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. 

(3) Represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices. As of December 31, 2015, the remaining balance of $70 million is included in current regulatory assets on the Consolidated Balance Sheets.

(4) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.

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, 2015 and 2014, the Utility had current regulatory liabilities of $676 million and $261 million, respectively. At December 31, 2015, the current regulatory liabilities consisted primarily of a $400 million bill credit to the Utility’s natural gas customers resulting from the Penalty Decision. (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 comprised of the following:

	Balance at December 31,
(in millions)	2015		2014
Cost of removal obligations (1)	$	4,605	$	4,211
Recoveries in excess of AROs (2)		631		754
Public purpose programs (3)		600		701
Other		485		624
Total long-term regulatory liabilities	$	6,321	$	6,290

(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.

(2) Represents the cumulative differences between ARO expenses and amounts collected in rates.  Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments.  (See Note 10 below.)

(3) 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.

Regulatory Balancing Accounts

The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings.  To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable.Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets.  These differences do not have an impact on net income.  Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected. 

Current regulatory balancing accounts receivable and payable are comprised of the following:

	Receivable
	Balance at December 31,
(in millions)	2015		2014
Electric distribution	$	380	$	344
Utility generation		122		261
Gas distribution		493		566
Energy procurement		262		608
Public purpose programs		155		109
Other		348		378
Total regulatory balancing accounts receivable	$	1,760	$	2,266

	Payable
	Balance at December 31,
(in millions)	2015		2014
Energy procurement	$	112	$	188
Public purpose programs		244		154
Other		359		748
Total regulatory balancing accounts payable	$	715	$	1,090

The electric distribution, utility generation, and gas distribution balancing accounts track the collection of revenue requirements approved in the GRC.  Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities.  Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency and low income energy efficiency.

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Debt

12 Months Ended

Dec. 31, 2015

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)	2015		2014
PG&E Corporation
Senior notes, 2.40%, due 2019		350		350
Total PG&E Corporation long-term debt		350		350
Utility
Senior notes:
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		400
3.25% due 2023		375		375
3.85% due 2023		300		300
3.40% due 2024		350		350
3.75% due 2024		450		450
3.50% due 2025		600		-
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		400
3.75% due 2042		350		350
4.60% due 2043		375		375
5.125% due 2043		500		500
4.75% due 2044		675		675
4.30% due 2045		600		500
4.25% due 2046		450		-
Unamortized discount, net of premium		(53)		(43)
Total senior notes, net of current portion		14,572		13,432
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 (1), due 2016 and 2026 (4)		309		309
Less: current portion		(160)		-
Total pollution control bonds		1,108		1,268
Total Utility long-term debt, net of current portion		15,680		14,700
Total consolidated long-term debt, net of current portion	$	16,030	$	15,050

(1) At December 31, 2015, interest rates on these bonds were 0.01%.

(2) Each series of these bonds is supported by a separate letter of credit.  In December 2015, the letters of credit were extended to December 1, 2020.  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) Each series of these bonds is supported by a separate direct-pay letter of credit. Series C and D letters of credit expire on December 3, 2016 to coincide with the maturity of the underlying bonds.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.

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.  Substantially all of the net proceeds 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.  In 1999, the Utility sold all bond-financed facilities at the non-retired units of 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 for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are outstanding.  Except for components that may have been abandoned in place or disposed of as scrap or that are permanently non-operational, the Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities.

Short-term Borrowings

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at December 31, 2015:

		Credit			Letters of			Commercial
	Termination	Facility			Credit			Paper			Facility
(in millions)	Date	Limit			Outstanding			Outstanding			Availability
PG&E Corporation	April 2020	$	300	(1)		$	-		$	-		$	300
Utility	April 2020		3,000	(2)			33			1,019			1,948
Total revolving credit facilities		$	3,300			$	33		$	1,019		$	2,248

(1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

(2) Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans.

For the year ended December 31,2015, PG&E Corporation’s average outstanding commercial paper balance was $64million and the maximum outstanding balance during the year was $128 million.  For 2015, the Utility’s average outstanding commercial paper balance was $678million and the maximum outstanding balance during the year was $1.5 billion.  There were no bank borrowings for both PG&E Corporation and the Utility in 2015. 

Revolving Credit Facilities

On April 27, 2015, PG&E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities.  The amendments and restatements extended the termination dates of the credit facilities from April 1, 2019 to April 27, 2020, reduced the amount of lender commitments to the letter of credit sublimits from $100 million to $50 million for PG&E Corporation’s credit facility and from $1.0 billion to $500 million for the Utility’s credit facility, and reduced the swingline commitment on the Utility’s credit facility from $300 million to $75 million.  PG&E Corporation's and the Utility's revolving credit facilities may be used for working capital, the repayment of commercial paper, and other corporate purposes.  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. 

Borrowings under each amended and restated credit agreement (other than swing line loans) will bear interest based, at each borrower’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 overnight federal funds rate, and the one-month LIBOR plus an applicable margin.  The applicable margin for LIBOR loans will range between 0.9% and 1.475% under PG&E Corporation’s amended and restated credit agreement and between 0.8% and 1.275% under the Utility’s amended and restated credit agreement. The applicable margin for base rate loans will range between 0% and 0.475% under PG&E Corporation’s amended and restated credit agreement and between 0% and 0.275% under the Utility’s amended and restated credit agreement.  In addition, the facility fee under PG&E Corporation’s and the Utility’s amended and restated credit agreements will range between 0.1% and 0.275% and between 0.075% and 0.225%, respectively.

PG&E Corporation’s and the Utility’s revolving credit facilities include usual and customary provisions for revolving credit facilities of this type, including those regarding events of default and covenants limiting liens to those permitted under their senior note indentures, mergers, sales of all or substantially all of their assets, and other fundamental changes.  In addition, the respective 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 outstanding common stock and at least 70% of the outstanding voting capital stock of the Utility. 

Commercial Paper Programs

The borrowings from PG&E Corporation and the Utility’s commercial paper programs are used primarily to fund temporary financing needs.  On July 2, 2015, the Utility increased the commercial paper program limit from $1.75 billion to $2.5 billion. PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and $2.5 billion, respectively. PG&E Corporation and the Utility treat the amount of outstanding commercial paper as a reduction to the amount available under their respective revolving credit facilities.  The commercial paper may have maturities up to 365 days and ranks equally with PG&E Corporation’s and 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.  For 2015, the average yield on outstanding PG&E Corporation and Utility commercial paper was 0.38% and 0.42%, respectively.

Other Short-term Borrowings

On May 11, 2015, $300 million principal amount of the Utility’s Floating Rate Senior Notes matured.

Repayment Schedule

PG&E Corporation’s and the Utility’s combined long-term debt principal repayment amounts at December 31, 2015 are reflected in the table below:

(in millions,
except interest rates)	2016			2017				2018				2019				2020				Thereafter				Total
PG&E Corporation
Average fixed interest rate		-				-				-				2.40	%			-				-				2.40
Fixed rate obligations	$	-			$	-			$	-			$	350			$	-			$	-			$	350
Utility
Average fixed interest rate		-				5.63	%			8.25	%			-				3.50	%			4.91	%			5.05
Fixed rate obligations	$	-			$	700			$	800			$	-			$	800			$	12,670			$	14,970
Variable interest rate
as of December 31, 2015		0.01	%			-				-				0.01	%			0.01	%			-				0.01
Variable rate obligations (1)	$	160			$	-			$	-			$	149			$	614			$	-			$	923
Total consolidated debt	$	160			$	700			$	800			$	499			$	1,414			$	12,670			$	16,243

(1) These bonds, due in 2016 and 2026, are backed by separate letters of credit that expire on December 3, 2016, June 5, 2019, or December 1, 2020.

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Common Stock And Share-Based Compensation

12 Months Ended

Dec. 31, 2015

Common Stock And Share-Based Compensation

NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 492,025,443 shares of common stock outstanding at December 31, 2015.  PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2015.

In February 2015, PG&E Corporation entered into a new equity distribution agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $500 million.  During 2015, PG&E Corporation sold   1.4 million shares under this agreement for cash proceeds of $74 million, net of commissions paid of $1 million.

In August 2015, PG&E Corporation sold 6.8 million shares of its common stock in an underwritten public offering for cash proceeds of $352 million, net of fees.

In addition, during 2015, PG&E Corporation sold 7.9 million shares of common stock under its 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans for total cash proceeds of $354 million.

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.  For 2015, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.455 per share.

Under their respective credit agreements, PG&E Corporation and the Utility are each required to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%. In addition, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on a weighted average over four years. PG&E Corporation and the Utility are in compliance with these restrictions. At December 31, 2015, the Utility had restricted net assets of $15.2 billion and was limited to $110 million of additional common stock dividends it could pay to PG&E Corporation.

Long-Term Incentive Plan

The PG&E Corporation LTIP permits various forms of share-based incentive awards, including restricted stock awards, restricted stock units, performance shares, 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 certain share-based awards.  In May 2014, the 2006 LTIP was terminated and the 2014 LTIP became effective.  A maximum of 17 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the 2014 LTIP, of which 15,674,803 shares were available for future awards at December 31, 2015.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2015, 2014, and 2013:

(in millions)	2015		2014		2013
Restricted stock units	$	47	$	42	$	36
Performance shares		46		36		28
Total compensation expense (pre-tax)	$	93	$	78	$	64
Total compensation expense (after-tax)	$	55	$	47	$	38

The amount of share-based compensation costs capitalized during 2015, 2014, and 2013 was immaterial.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Restricted Stock Units

Prior to 2014, restricted stock units generally vested over four years 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.  Restricted stock units granted in 2014 and 2015 generally vest equally over three years.  Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units.  Compensation expense is generally recognized rateably over the vesting period based on grant-date fair value.  The weighted average grant-date fair value for restricted stock units granted during 2015, 2014, and 2013 was $53.30, $43.76, and $42.92, respectively.  The total fair value of restricted stock units that vested during 2015, 2014, and 2013 was $57Error! Bookmark not defined.million, $34 million, and $30 million, respectively.  The tax benefit from restricted stock units that vested during each period was not material.  As of December 31, 2015, $45 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.48years.

The following table summarizes restricted stock unit activity for 2015:

	Number of	Weighted Average Grant-
	Restricted Stock Units	Date Fair Value
Nonvested at January 1	2,538,357	$	43.39
Granted	820,834	$	53.30
Vested	(1,304,150)	$	43.51
Forfeited	(82,142)	$	45.63
Nonvested at December 31	1,972,899	$	47.33

Performance Shares

Performance shares generally will vest three years after the grant date.  Upon vesting, performance shares are settled in shares of common stock based on PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period.  Dividend equivalents are paid in cash based on the amount of common stock to which the recipients are entitled. 

Compensation expense attributable to performance share is generally recognized rateably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model.  The weighted average grant-date fair value for performance shares granted during 2015, 2014, and 2013 was $68.27, $51.81, and $33.45 respectively.  There was no tax benefit associated with performance shares during each of these periods.  As of December 31, 2015, $36 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.45 years.

The following table summarizes activity for performance shares in 2015:

	Number of	Weighted Average Grant-
	Performance Shares	Date Fair Value
Nonvested at January 1	1,693,939	$	42.37
Granted	669,519		68.27
Vested	(421,262)		33.57
Forfeited (1)	(491,584)		35.56
Nonvested at December 31	1,450,612	$	59.24
(1) Includes performance shares that expired with 50% value as a result of total shareholder return results.

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Preferred Stock

12 Months Ended

Dec. 31, 2015

Preferred Stock

NOTE 6: PREFERRED STOCK

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.

The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value preferred stock.  At December 31, 2015 and December 31, 2014, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share.  The Utility’s preferred stock outstanding are not subject to mandatory redemption.  All outstanding preferred stock has a $25 par value.

At December 31, 2015, 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, 2015, 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. The Utility paid $14 million of dividends on preferred stock in each of 2015, 2014, and 2013.

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Earnings Per Share

12 Months Ended

Dec. 31, 2015

Earnings Per Share

NOTE 7: EARNINGS PER SHARE

PG&E Corporation’s basic 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 2015, 2014, and 2013.

	Year Ended December 31,
(in millions, except per share amounts)	2015		2014		2013
Income available for common shareholders	$	874	$	1,436	$	814
Weighted average common shares outstanding, basic		484		468		444
Add incremental shares from assumed conversions:
Employee share-based compensation		3		2		1
Weighted average common share outstanding, diluted		487		470		445
Total earnings per common share, diluted	$	1.79	$	3.06	$	1.83

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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Income Taxes

12 Months Ended

Dec. 31, 2015

Income Taxes

NOTE 8: INCOME TAXES

PG&E Corporation and the Utility use the liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year.  PG&E Corporation and the Utility estimate current period 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 those arising from depreciation expense. 

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 in the financial statements represents an unrecognized tax benefit. 

Investment tax credits are deferred and amortized to income over time.  PG&E Corporation amortizes its investment tax credits over the projected investment recovery period.  The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.

PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more.  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. 

The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2015		2014		2013		2015		2014		2013
Current:
Federal	$	(89)	$	(84)	$	(218)	$	(88)	$	(84)	$	(222)
State		11		(41)		(26)		6		(29)		(23)
Deferred:
Federal		131		396		552		136		426		604
State		(76)		78		(35)		(69)		75		(28)
Tax credits		(4)		(4)		(5)		(4)		(4)		(5)
Income tax provision	$	(27)	$	345	$	268	$	(19)	$	384	$	326

The following table describes net deferred income tax liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2015		2014		2015		2014
Deferred income tax assets:
Customer advances for construction	$	69	$	88	$	69	$	88
Environmental reserve		85		111		85		111
Compensation and benefits		219		244		145		173
Tax carryforwards		1,703		1,177		1,462		946
Greenhouse gas allowances		340		56		340		56
Other		44		74		61		100
Total deferred income tax assets	$	2,460	$	1,750	$	2,162	$	1,474
Deferred income tax liabilities:
Regulatory balancing accounts	$	691	$	512	$	691	$	512
Property related basis differences		9,656		8,683		9,638		8,666
Income tax regulatory asset (1)		1,244		974		1,245		974
Other		75		88		75		86
Total deferred income tax liabilities	$	11,666	$	10,257	$	11,649	$	10,238
Total net deferred income tax liabilities	$	9,206	$	8,507	$	9,487	$	8,764
Classification of net deferred income tax liabilities:
Included in current liabilities (assets)	$	-	$	(6)	$	-	$	(9)
Included in noncurrent liabilities		9,206		8,513		9,487		8,773
Total net deferred income tax liabilities	$	9,206	$	8,507	$	9,487	$	8,764

(1)Represents the deferred income tax component of the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP.  (See Note 3 above.)

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,
	2015			2014			2013			2015				2014			2013
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) (1)	(4.9)		1.4			(3.1)			(4.8)				1.6			(2.2)
Effect of regulatory treatment
of fixed asset differences (2)	(33.6)		(15.0)			(4.2)			(33.7)				(14.7)			(3.8)
Tax credits	(1.3)		(0.7)			(0.4)			(1.3)				(0.7)			(0.4)
Benefit of loss carryback	(1.5)		(0.8)			(1.1)			(1.5)				(0.8)			(1.0)
Non deductible penalties (3)	4.3		0.3			0.8			4.3				0.3			0.7
Other, net	(1.1)		(0.8)			(2.2)			(0.2)				0.4			(0.9)
Effective tax rate	(3.1)	%	19.4		%	24.8		%	(2.2)			%	21.1		%	27.4		%

(1)Includes the effect of state flow-through ratemaking treatment.  In 2015, amounts include an agreement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions.   

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs in 2015 and 2014 as authorized by the 2014 GRC decision.  Amounts are impacted by the level of income before income taxes. 

(3) Represents the effects of non-tax deductible fines and penalties associated with the Penalty Decision.  (For more information about the Penalty Decision see Note 13 below.)

Unrecognized tax benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation						Utility
(in millions)	2015		2014		2013		2015		2014		2013
Balance at beginning of year	$	713	$	666	$	581	$	707	$	660	$	575
Additions for tax position taken
during a prior year		40		7		12		40		7		12
Reductions for tax position
taken during a prior year		(349)		(9)		(6)		(349)		(9)		(6)
Additions for tax position
taken during the current year		64		61		79		64		61		79
Settlements		-		(12)		-		-		(12)		-
Balance at end of year	$	468	$	713	$	666	$	462	$	707	$	660

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2015 for PG&E Corporation and the Utility was $50 million.

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of several matters, including audits. As of December 31, 2015, it is reasonably possible that unrecognized tax benefits will decrease by approximately $60 million within the next 12 months.

Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income.  For the years ended December 31, 2015, 2014, and 2013, these amounts were immaterial.

IRS settlements

PG&E Corporation participated in the Compliance Assurance Process in 2015, a real-time IRS audit intended to expedite resolution of tax matters.  The Compliance Assurance Process audit culminates with a letter from the IRS indicating its acceptance of the return.

PG&E Corporation’s tax returns have been accepted through 2014 except for a few matters, the most significant of which relates to deductible repair costs.  In December 2015, PG&E Corporation reached an agreement with the IRS on deductible repair costs for the 2011 tax year, subject to approval by the Joint Committee on Taxation.  Deductible repair costs will continue to be subject to examination by the IRS for subsequent years.  The IRS is expected to issue guidance in 2016 that clarifies which repair costs are deductible for the natural gas transmission and distribution businesses.  Tax years after 2004 remain subject to examination by the state of California.

Carryforwards

The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:

	December 31,		Expiration
(in millions)	2015		Year
Federal:
Net operating loss carryforward	$	4,856	2029 - 2035
Tax credit carryforward		110	2029 - 2035
Charitable contribution loss carryforward		178	2017 - 2020
State:
Net operating loss carryforward	$	80	2033 - 2034
Tax credit carryforward		59	Various
Charitable contribution loss carryforward		119	2019 - 2020

PG&E Corporation believes it is more likely than not the tax benefits associated with the federal and California net operating losses, charitable contributions and tax credits can be realized within the carryforward periods, therefore no valuation allowance was recognized as of December 31, 2015 for these tax attributes. As of December 31, 2015, PG&E Corporation had approximately $29 million of federal net operating loss carryforwards related to the tax benefit on employee stock plans that would be recorded in additional paid-in capital when used.

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Derivatives And Hedging Activities

12 Months Ended

Dec. 31, 2015

Derivatives And Hedging Activities

NOTE 9: DERIVATIVES

Use of Derivative Instruments

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities.  Procurement costs are recovered through customer rates.  The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices.  Derivatives include forward contracts, swaps, futures, options, and CRRs.

Derivatives are presented in the Utility’s Consolidated Balance Sheets on a net basis in accordance with master netting arrangements for each counterparty.  The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.  

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets.  These instruments are not held for speculative purposes and are subject to certain regulatory requirements.  The Utility expects to fully recover in rates all costs related to derivatives as long as the current ratemaking mechanism remains in place and the Utility’s price risk management activities are carried out in accordance with CPUC directives.  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.  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.  Eligible derivatives are those 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.  These items are not reflected in the Consolidated Balance Sheets at fair value.  Eligible derivatives are accounted for under the accrual method of accounting.

Volume of Derivative Activity

At December 31,2015 and 2014, respectively, the volumes of the Utility’s outstanding derivatives were as follows:

		Contract Volume
Underlying Product	Instruments	2015	2014
Natural Gas (1) (MMBtus (2))	Forwards and Swaps	333,091,813	308,130,101
	Options	111,550,004	164,418,002
Electricity (Megawatt-hours)	Forwards and Swaps	3,663,512	5,346,787
	Congestion Revenue Rights (3)	216,383,389	224,124,341

(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.

(2) Million British Thermal Units.

(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

At December 31, 2015, 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	$	97	$		(4)	$		25	$		118
Other noncurrent assets – other		172			(2)			-			170
Current liabilities – other		(102)			4			44			(54)
Noncurrent liabilities – other		(140)			2			21			(117)
Total commodity risk	$	27	$		-	$		90	$		117

At December 31, 2014, 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	$	73	$		(4)	$		19	$		88
Other noncurrent assets – other		178			(13)			-			165
Current liabilities – other		(78)			4			26			(48)
Noncurrent liabilities – other		(140)			13			9			(118)
Total commodity risk	$	33	$		-	$		54	$		87

Gains and losses associated with price risk management activities were recorded as follows:

	Commodity Risk
	For the year ended December 31,
(in millions)	2015		2014		2013
Unrealized gain/(loss) - regulatory assets and liabilities (1)	$	(6)	$	124	$	238
Realized loss - cost of electricity (2)		(14)		(83)		(178)
Realized loss - cost of natural gas (2)		(10)		(8)		(22)
Total commodity risk	$	(30)	$	33	$	38

(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, 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 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, 2015, 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)	2015		2014
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(2)	$	(47)
Related derivatives in an asset position		-		-
Collateral posting in the normal course of business related to
these derivatives		-		44
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(2)	$	(3)

(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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Fair Value Measurements

12 Months Ended

Dec. 31, 2015

Fair Value Measurements

NOTE 10: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, price risk management instruments, and other investments at fair value.  A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

• Level1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

• Level2 – Other inputs that are directly or indirectly observable in the marketplace.

• Level3 – 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 and other investments are held by PG&E Corporation and not the Utility):

	Fair Value Measurements
	At December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	64	$	-	$	-	$	-	$	64
Nuclear decommissioning trusts
Money market investments		36		-		-		-		36
Global equity securities		1,520		13		-		-		1,533
Fixed-income securities		694		521		-		-		1,215
Total nuclear decommissioning trusts (2)		2,250		534		-		-		2,784
Price risk management instruments
(Note 9)
Electricity		-		9		259		18		286
Gas		-		1		-		1		2
Total price risk management
instruments		-		10		259		19		288
Rabbi trusts
Fixed-income securities		-		57		-		-		57
Life insurance contracts		-		70		-		-		70
Total rabbi trusts		-		127		-		-		127
Long-term disability trust
Money market investments		7		-		-		-		7
Global equity securities		-		26		-		-		26
Fixed-income securities		-		132		-		-		132
Total long-term disability trust		7		158		-		-		165
Total assets	$	2,321	$	829	$	259	$	19	$	3,428
Liabilities:
Price risk management instruments
(Note 9)
Electricity	$	69	$	1	$	170	$	(70)	$	170
Gas		-		2		-		(1)		1
Total liabilities	$	69	$	3	$	170	$	(71)	$	171

(1)Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $314 million, primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2014
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	94	$	-	$	-	$	-	$	94
Nuclear decommissioning trusts
Money market investments		17		-		-		-		17
Global equity securities		1,585		13		-		-		1,598
Fixed-income securities		741		389		-		-		1,130
Total nuclear decommissioning trusts (2)		2,343		402		-		-		2,745
Price risk management instruments
(Note 9)
Electricity		-		17		232		2		251
Gas		1		1		-		-		2
Total price risk management
instruments		1		18		232		2		253
Rabbi trusts
Fixed-income securities		-		42		-		-		42
Life insurance contracts		-		72		-		-		72
Total rabbi trusts		-		114		-		-		114
Long-term disability trust
Money market investments		7		-		-		-		7
Global equity securities		-		25		-		-		25
Fixed-income securities		-		128		-		-		128
Total long-term disability trust		7		153		-		-		160
Other investments		33		-		-		-		33
Total assets	$	2,478	$	687	$	232	$	2	$	3,399
Liabilities:
Price risk management instruments
(Note 9)
Electricity	$	47	$	5	$	163	$	(52)	$	163
Gas		-		3		-		-		3
Total liabilities	$	47	$	8	$	163	$	(52)	$	166

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $324 million, 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 tables above.  Investments, primarily consisting of equity securities, that are valued using a net asset value per share can be redeemed quarterly with notice not to exceed 90 days.  Equity investments valued at net asset value per share utilize investment strategies aimed at matching the performance of indexed funds.  Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the year ended December 31, 2015 and 2014.

Trust Assets

Nuclear decommissioning trust assets and other trust assets are composed primarily of equity securities and debt securities.  In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.  Equity securities also include commingled funds that are composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world. Investments in these funds are classified as Level 2 because price quotes 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 using 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. 

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.  Exchange-traded options are valued using observable market data and market-corroborated data and 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.  Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.

Level 3 Measurements and Sensitivity Analysis

The Utility’s market and credit risk management function, which reports to the Chief Risk and Audit Officer of the Utility, is responsible for determining the fair value of the Utility’s price risk management derivatives.  The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative.  Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

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 9 above.)

	Fair Value at
(in millions)	At December 31, 2015				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	259	$	63	Market approach	CRR auction prices	$	(161.36) - 8.76
Power purchase agreements	$	-	$	107	Discounted cash flow	Forward prices	$	15.08 - 37.27

1. Represents price per megawatt-hour

	Fair Value at
(in millions)	At December 31, 2014				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	232	$	63	Market approach	CRR auction prices	$	(15.97) - 8.17
Power purchase agreements	$	-	$	100	Discounted cash flow	Forward prices	$	16.04 - 56.21

(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, 2015 and 2014, respectively:

	Price Risk Management Instruments
(in millions)	2015		2014
Asset (liability) balance as of January 1	$	69		$	(30)
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		20			99
Asset (liability) balance as of December 31	$	89		$	69

    (1) The costs related to 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, floating rate senior notes, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2015 and 2014, 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 bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at December 31, 2015 and 2014.

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,
	2015					2014
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount			Level 2 Fair Value
Debt (Note 4)
PG&E Corporation	$	350	$	354	$		350	$	352
Utility		14,918		16,422			13,778		15,851

Available for Sale Investments

The following table provides a summary of available-for-sale investments:

				Total		Total
	Amortized			Unrealized		Unrealized		Total Fair
(in millions)	Cost			Gains		Losses		Value
As of December 31, 2015
Nuclear decommissioning trusts
Money market investments	$	36	$	-	$	-	$	36
Global equity securities		508		1,034		(9)		1,533
Fixed-income securities		1,165		58		(8)		1,215
Total (1)	$	1,709	$	1,092	$	(17)	$	2,784
As of December 31, 2014
Nuclear decommissioning trusts
Money market investments	$	17	$	-	$	-	$	17
Global equity securities		520		1,087		(9)		1,598
Fixed-income securities		1,059		75		(4)		1,130
Total nuclear decommissioning trusts (1)		1,596		1,162		(13)		2,745
Other investments		5		28		-		33
Total	$	1,601	$	1,190	$	(13)	$	2,778

(1) Represents amounts before deducting $314 million and $324 million at December 31, 2015 and 2014, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of debt securities by contractual maturity is as follows:

	As of
(in millions)	December 31, 2015
Less than 1 year	$	18
1–5 years		470
5–10 years		273
More than 10 years		454
Total maturities of debt securities	$	1,215

The following table provides a summary of activity for the debt and equity securities:

	2015		2014		2013
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust
investments	$	1,268	$	1,336	$	1,619
Gross realized gains on sales of securities held as available-for-sale		55		118		94
Gross realized losses on sales of securities held as available-for-sale		(37)		(12)		(13)

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2015

Employee Benefit Plans

NOTE 11: EMPLOYEE BENEFIT PLANS

Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”).  The trusts underlying certain of these plans are qualified trusts under the Internal Revenue Code of 1986, as amended.  If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations.  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 is zero. 

PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.  PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans.

Change in Plan Assets, Benefit Obligations, and Funded Status

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2015 and 2014:

Pension Plan

(in millions)	2015		2014
Change in plan assets:
Fair value of plan assets at beginning of year	$	14,216		$	12,527
Actual return on plan assets		(176)			1,946
Company contributions		334			332
Benefits and expenses paid		(629)			(589)
Fair value of plan assets at end of year	$	13,745		$	14,216
Change in benefit obligation:
Benefit obligation at beginning of year	$	16,696		$	14,077
Service cost for benefits earned		479			383
Interest cost		673			695
Actuarial (gain) loss		(922)			2,131
Plan amendments		1			(1)
Transitional costs		1			-
Benefits and expenses paid		(629)			(589)
Benefit obligation at end of year (1)	$	16,299		$	16,696
Funded Status:
Current liability	$	(6)		$	(6)
Noncurrent liability		(2,547)			(2,474)
Net liability at end of year	$	(2,553)		$	(2,480)

(1)PG&E Corporation’s accumulated benefit obligation was $14.7billion and $14.9 billion at December 31, 2015 and 2014, respectively.

Postretirement Benefits Other than Pensions

(in millions)	2015		2014
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,092		$	1,892
Actual return on plan assets		(26)			241
Company contributions		61			57
Plan participant contribution		68			63
Benefits and expenses paid		(160)			(161)
Fair value of plan assets at end of year	$	2,035		$	2,092
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,811		$	1,597
Service cost for benefits earned		55			45
Interest cost		71			76
Actuarial (gain) loss		(98)			166
Transitional costs		1			-
Benefits and expenses paid		(146)			(140)
Federal subsidy on benefits paid		4			4
Plan participant contributions		68			63
Benefit obligation at end of year	$	1,766		$	1,811
Funded Status: (1)
Noncurrent asset	$	344		$	368
Noncurrent liability		(75)			(87)
Net asset at end of year	$	269		$	281

(1) At December 31, 2015 and 2014, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Components of Net Periodic Benefit Cost

Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:

Pension Plan

(in millions)	2015		2014			2013
Service cost	$	479		$	383		$	468
Interest cost		673			695			627
Expected return on plan assets		(873)			(807)			(650)
Amortization of prior service cost		15			20			20
Amortization of net actuarial loss		10			2			111
Net periodic benefit cost		304			293			576
Less: transfer to regulatory account (1)		34			42			(238)
Total expense recognized	$	338		$	335		$	338

(1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.

Postretirement Benefits Other than Pensions

(in millions)	2015		2014			2013
Service cost	$	55		$	45		$	53
Interest cost		71			76			74
Expected return on plan assets		(112)			(103)			(79)
Amortization of prior service cost		19			23			23
Amortization of net actuarial loss		4			2			6
Net periodic benefit cost	$	37		$	43		$	77

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 unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax.  In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions. For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income. For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income. As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss).

The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2016 are as follows:

(in millions)	Pension Plan		PBOP Plans
Unrecognized prior service cost	$	8	$	15
Unrecognized net loss		24		4
Total	$	32	$	19

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 Plan						PBOP Plans
	December 31,						December 31,
	2015		2014		2013		2015		2014		2013
Discount rate	4.37	%	4.00	%	4.89	%	4.27 - 4.48	%	3.89 - 4.09	%	4.70 - 5.00	%
Rate of future compensation
increases	4.00	%	4.00	%	4.00	%	-		-		-
Expected return on plan
assets	6.10	%	6.20	%	6.50	%	3.20 - 6.60	%	3.30 - 6.70	%	3.50 - 6.70	%

The assumed health care cost trend rate as of December 31, 2015 was 7.2%, decreasing gradually to an ultimate trend rate in 2024 and beyond of approximately 4%.  A one-percentage-point change in assumed health care cost trend rate would have the following effects:

	One-Percentage-Point		One-Percentage-Point
(in millions)	Increase		Decrease
Effect on postretirement benefit obligation	$	113	$	(114)
Effect on service and interest cost		9		(9)

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets.  Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate.  Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added to a long-term inflation rate.  For the pension plan, the assumed return of 6.1% compares to a ten-year actual return of 7.8%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 688 Aa-grade non-callable bonds at December 31, 2015.  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.

Investment Policies and Strategies

The financial position of PG&E Corporation’s and the Utility’s 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 in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended.  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. 

The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings.  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 trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields.  To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments.  Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return.  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, REITS, global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios.

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.  Derivative instruments such as equity index futures are used to meet target equity exposure.  In addition, derivative instruments such as equity index futures and U.S. treasury futures are used 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 non U.S. dollar exposure of global equity investments.

The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:

	Pension Plan								PBOP Plans
	2016		2015			2014			2016			2015			2014
Global equity	25	%		25	%		25	%		32	%		31	%		30	%
Absolute return	5	%		5	%		5	%		3	%		3	%		3	%
Real assets	10	%		10	%		10	%		7	%		8	%		8	%
Fixed income	60	%		60	%		60	%		58	%		58	%		59	%
Total	100	%		100	%		100	%		100	%		100	%		100	%

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.

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, 2015 and 2014. 

	Fair Value Measurements
	At December 31,
	2015												2014
(in millions)	Level 1			Level 2			Level 3			Total				Level 1			Level 2			Level 3			Total
Pension Plan:
Short-term investments	$	247	$		369	$		-	$		616	$			352	$		311	$		-	$		663
Global equity		903			2,243			-			3,146				918			2,311			-			3,229
Absolute return		-			-			660			660				-			-			577			577
Real assets		581			-			753			1,334				620			-			675			1,295
Fixed-income		1,841			5,516			640			7,997				2,068			5,718			638			8,424
Total	$	3,572	$		8,128	$		2,053	$		13,753	$			3,958	$		8,340	$		1,890	$		14,188
PBOP Plans:
Short-term investments	$	20	$		-	$		-	$		20	$			28	$		-	$		-	$		28
Global equity		104			545			-			649				124			549			-			673
Absolute return		-			-			65			65				-			-			55			55
Real assets		69			-			77			146				72			-			49			121
Fixed-income		150			1,010			-			1,160				163			1,055			1			1,219
Total	$	343	$		1,555	$		142	$		2,040	$			387	$		1,604	$		105	$		2,096
Total plan assets at fair value									$		15,793											$		16,284

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $13 million and $24 million at December 31, 2015 and 2014, respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable.

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.

Short-Term Investments

Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets.

Global Equity

The global equity category includes investments in common stock, equity-index futures, and commingled funds comprised of equity securities spread 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.  Commingled equity 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 equity 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 equity funds are categorized as Level 1 and 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 commodity futures, global REITS, global listed infrastructure equities, and private real estate funds.  The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore 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 privately placed debt portfolios which 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 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 Treasury futures.  Municipal bonds are valued based on a compilation of primarily observable information or broker quotes in non-active markets and are considered Level 2 assets.  Futures are valued based on unadjusted prices in active markets and are Level 1 assets.

Transfers Between Levels

Any transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period.  No material transfers between levels occurred in the years ended December 31, 2015 and 2014.

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, 2015 and 2014:

	Pension Plan
(in millions)	Absolute		Fixed-
For the year ended December 31, 2015	Return		Income		Real Assets		Total
Balance at beginning of year	$	577	$	638	$	675	$	1,890
Actual return on plan  assets:
Relating to assets still held at the reporting date		(7)		9		63		65
Relating to assets sold during the period		-		1		-		1
Purchases, issuances, sales, and settlements:
Purchases		90		2		17		109
Settlements		-		(10)		(2)		(12)
Balance at end of year	$	660	$	640	$	753	$	2,053
	Pension Plan
(in millions)	Absolute		Fixed-
For the year ended December 31, 2014	Return		Income		Real Assets		Total
Balance at beginning of year	$	554	$	625	$	544	$	1,723
Actual return on plan assets:
Relating to assets still held at the reporting date		23		24		54		101
Relating to assets sold during the period		-		4		-		4
Purchases, issuances, sales, and settlements:
Purchases		-		1		78		79
Settlements		-		(16)		(1)		(17)
Balance at end of year	$	577	$	638	$	675	$	1,890

	PBOP Plans
(in millions)	Absolute			Fixed-
For the year ended December 31, 2015	Return			Income			Real Assets			Total
Balance at beginning of year	$	55	$		1	$		49	$		105
Actual return on plan  assets:
Relating to assets still held at the reporting date		(1)			-			5			4
Relating to assets sold during the period		-			-			-			-
Purchases, issuances, sales, and settlements:
Purchases		11			-			23			34
Settlements		-			(1)			-			(1)
Balance at end of year	$	65	$		-	$		77	$		142
	PBOP Plans
(in millions)	Absolute			Fixed-
For the year ended December 31, 2014	Return			Income			Real Assets			Total
Balance at beginning of year	$	53	$		2	$		38	$		93
Actual return on plan assets:
Relating to assets still held at the reporting date		2			-			4			6
Relating to assets sold during the period		-			-			-			-
Purchases, issuances, sales, and settlements:
Purchases		-			-			7			7
Settlements		-			(1)			-			(1)
Balance at end of year	$	55	$		1	$		49	$		105

There were no material transfers out of Level 3 in 2015 and 2014.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $334 million to the pension benefit plans and $61 million to the other benefit plans in 2015.  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 2015.  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 $61 million to the pension plan and other postretirement benefit plans, respectively, for 2016.

Benefits Payments and Receipts

As of December 31, 2015, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:

	Pension		PBOP			Federal
(in millions)	Plan		Plans			Subsidy
2016	$	695		$	89		$	(6)
2017		739			95			(7)
2018		780			101			(7)
2019		818			107			(8)
2020		854			113			(8)
Thereafter in the succeeding five years		4,728			593			(17)

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 also 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.

Retirement Savings Plan

PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended.  This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants.  Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $89 million, $80 million, and $71 million in 2015, 2014, and 2013, respectively.

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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Related Party Agreements And Transactions

12 Months Ended

Dec. 31, 2015

Related Party Agreements And Transactions

NOTE 12: 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:

	Year Ended December 31,
(in millions)	2015		2014		2013
Utility revenues from:
Administrative services provided to PG&E Corporation	$	6	$	5	$	7
Utility expenses from:
Administrative services received from PG&E Corporation	$	53	$	54	$	45
Utility employee benefit due to PG&E Corporation		82		70		57

At December 31, 2015 and 2014, the Utility had receivables of $22Error! Bookmark not defined. million and $17 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 $21 million and $20 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2015

Commitments And Contingencies

NOTE 13: CONTINGENCIES AND COMMITMENTS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation.  The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below.   PG&E Corporation has financial commitments described in “Other Commitments” below.

Enforcement and Litigation Matters

CPUC Matters

Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

During 2014 and 2015, the Utility filed several reports to notify the CPUC of communications that the Utility believes may have constituted or described ex parte communications that either should not have been made or that should have been timely reported to the CPUC. Ex parte communications include communications between a decision maker or a Commissioner’s advisor and interested persons concerning substantive issues in certain formal proceedings. Certain communications are prohibited and others are permissible with proper noticing and reporting.

On November 23, 2015, the CPUC issued an OII into whether the Utility should be sanctioned for violating rules pertaining to ex parte communications and Rule 1.1 of the CPUC’s Rules of Practice and Procedure governing the conduct of those appearing before the CPUC.  The OII cites some of the communications the Utility reported to the CPUC.  The OII also cites the ex parte violations alleged in the City of San Bruno’s July 2014 motion, which it filed in the CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices.  A prehearing conference in the OII has been scheduled for March 1, 2016.

The CPUC will determine any penalties that might be imposed on the Utility and determine whether shareholders or ratepayers will bear the costs of the investigation. The CPUC can impose fines up to $50,000 for each violation, per day.The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as how many days each violation continued; 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.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the OII but they are unable to reasonably estimate the amount or range of future charges that could be incurred, because it is uncertain how the CPUC will calculate the number of violations or the penalty for any violations, and whether the CPUC will consider additional communications in the OII, including those identified in a motion filed on December 1, 2015, by the City of San Bruno in the 2015 GT&S rate case.  It is also uncertain whether the CPUC will take additional action in any of the proceedings in which the Utility has self-reported communications that may have violated the CPUC’s ex parte rules. 

Finally, the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office also have been investigating matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility is cooperating with the federal and state investigators. It is uncertain whether any charges will be brought against the Utility.

CPUC Investigation Regarding Natural Gas Distribution FacilitiesRecord-Keeping

On November 20, 2014, the CPUC began an investigation into whether the Utility violated applicable laws pertaining to record-keeping practices with respect to maintaining safe operation of its natural gas distribution service and facilities.  The order also requires the Utility to show cause why (1) the CPUC should not find that the Utility violated provisions of the California Public Utilities Code, CPUC general orders or decisions, other rules, or requirements, and/or engaged in unreasonable and/or imprudent practices related to these matters, and (2) the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found.  In particular, the order cites the SED’s investigative reports alleging that the Utility violated rules regarding safety record-keeping in connection with six natural gas distribution incidents, including the natural gas explosion that occurred in Carmel, California on March 3, 2014, for which the CPUC has previously imposed a penalty of $10.85 million. 

On September 30, 2015, the SED submitted its supplemental testimony, which included incidents allegedly related to record-keeping that had not been identified in the initial order, and also asserted violations related to the Utility’s pre-excavation location and marking practices, causal evaluation practices, and compliance with regulations governing pressure validation for certain distribution facilities.  Evidentiary hearings were held during January 2016.  Opening briefs are due by February 26, 2016 and reply briefs are due by March 31, 2016.  The SED has indicated it will seek significant penalties, the amount of which is expected to be disclosed in its brief.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the form of fines or other remedies, including possible future unrecoverable costs to implement operational remedies. The Utility is unable to determine the form or amount of penalties or reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion (discussed above).

Natural Gas Transmission Pipeline Rights-of-Way   

In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey has been completed and that remediation work, including removal of the encroachments, is expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility or take other enforcement action in the future based on the Utility’s failure to continuously survey its system and remove encroachments.  The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties.

Potential Safety Citations

The SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations.In addition, the California utilities are required to inform the SED of self-identified or self-corrected violations. The CPUC has delegated authority to the SED to issue citations and impose fines for violations identified through audits, investigations, or self-reports. The SED can consider the discretionary factors discussed above (see “Order Instituting an Investigation into Compliance with Ex parte Communication Rules” above) in determining the number of violations and whether to impose daily fines for continuing violations. The SED is required, however, to impose the maximum statutory penalty of $50,000 for each separate violation.

The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations. The Utility believes it is probable that the SED will impose fines or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines imposed by the SED with respect to these matters given the wide discretion the SED has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.

Federal Matters

Federal Criminal Indictment

On July 29, 2014, a federal grand jury for the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court that superseded the original indictment that was returned on April 1, 2014.  The superseding indictment charges 27 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats.  The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident.  On December 23, 2015, the court presiding over the federal criminal proceeding dismissed 15 of the Pipeline Safety Act counts, leaving 13remaining counts.  The maximum statutory fine for each felony count is $500,000, for total potential fines of $6.5 million. On December 8, 2015, the court alsoissued an order granting, in part, the Utility’s request to dismiss the government’s allegations seeking an alternative fine under the Alternative Fines Act.  The Alternative Fines Act states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.”  The court dismissed the government’s allegations regarding the amount of losses, but concluded that it required additional information about how the government would prove its allegations about the amount of gross gains prior to deciding whether to dismiss those allegations.  (Based on the superseding indictment’s allegation that the Utility derived gross gains of approximately $281 million, the potential maximum alternative fine would be approximately $562 million.) After considering the additional information submitted by the government, on February 2, 2016, the court issued an order holding that if the government’s allegations about the Utility’s gross gains are considered, they would be considered in a second trial phase that would take place after the trial on the criminal charges.  The trial on the criminal charges currently is scheduled to begin March 22, 2016.

The Utility entered a plea of not guilty.The Utility believes that criminal charges and the alternative fine allegations are not merited and that it did not knowingly and willfully violate minimum safety standards under the Natural Gas Pipeline Safety Act or obstruct the NTSB’s investigation, as alleged in the superseding indictment.  PG&E Corporation and the Utility have not accrued any charges for criminal fines in their Consolidated Financial Statements as such amounts are not considered to be probable.

Other Federal Matters

The Utility was informed that the U.S. Attorney’s Office wasinvestigating a natural gas explosion that occurred in Carmel, California on March 3, 2014.  The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case discussed above.  It is uncertain whether any additional charges will be brought against the Utility.

Capital Expenditures Relating to Pipeline Safety Enhancement Plan

At December 31, 2015, approximately $664 million of PSEP-related capital costs is recorded in property, plant, and equipment on the Consolidated Balance Sheets. The Utility would be required to record charges to the statement of income in future periods to the extent total forecasted PSEP-related capital costs are higher than currently expected.

Penalty Decision Related to the CPUC’s Investigative Enforcement Proceedings Related to Natural Gas Transmission

On April 9, 2015, the CPUC approved final decisions in the three investigations that had been brought against the Utility relating to (1) the Utility’s safety record-keeping 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, record-keeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010.  A decision was issued in each investigative proceeding to determine the violations that the Utility committed.  The CPUC also approved a fourth decision (the “Penalty Decision”) which imposes penalties on the Utility totaling $1.6 billion comprised of: (1) a $300 million fine to be paid to the State General Fund, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million. In August 2015, the Utility paid the $300 million fine. At December 31, 2015, the Consolidated Balance Sheets include $400 million in current regulatory liabilities for the one-time bill credit that will be provided to the Utility’s natural gas customers in 2016.  On January 14, 2016, the CPUC issued final decisions to close these investigative proceedings.

The Penalty Decision requires that at least $689 million of the $850 million disallowance be allocated to capital expenditures, and that the Utility be precluded from including these capital costs in rate base.  The CPUC will determine which safety projects and programs will be funded by shareholders in the Utility’s pending 2015 GT&S rate case.  If the $850 million is not exhausted by designated safety-related projects and programs in the 2015 GT&S proceeding, the CPUC will identify additional projects in future proceedings to ensure that the full $850 million is spent. The CPUC is expected to issue a final decision in the Utility’s 2015 GT&S rate case in 2016 to identify safety-related projects and programs that will be subject to the disallowance. It is uncertain how much of the Utility’s costs to perform the safety-related projects and programs the CPUC will identify as counting toward the $850 million shareholder-funded obligation. If the Utility’s actual costs exceed costs that the CPUC counts towards the $850 million maximum, the Utility would record additional charges if such costs are not otherwise authorized by the CPUC.  As a result, the total shareholder-funded obligation could exceed $850 million. 

For the year ended December 31, 2015, the Utility recorded additional charges in operating and maintenance expenses in the Consolidated Statements of Income of $907 million as a result of the Penalty Decision. The cumulative charges at December 31, 2015, and the additional future charges to reach the $1.6 billion total are shown in the following table:

	Year		Cumulative		Future
	Ended		Charges		Charges
		December 31,		December 31,	and		Total
(in millions)	2015		2015		Costs		Amount
Fine payable to the state (1)	$	100	$	300	$	-	$	300
Customer bill credit		400		400		-		400
Charge for disallowed capital (2)		407		407		282		689
Disallowed revenue for pipeline safety
expenses (3)		-		-		161		161
CPUC estimated cost of other remedies (4)		-		-		-		50
Total Penalty Decision fines and remedies	$	907	$	1,107	$	473	$	1,600

(1) In March 2015, the Utility increased its accrual from $200 million at December 31, 2014 to $300 million.

(2) The Penalty Decision prohibits the Utility from recovering certain expenses and capital spending associated with pipeline safety-related projects and programs that the CPUC will identify in the final decision to be issued in the Utility’s 2015 GT&S rate case.The Utility estimates that approximately $407 million of capital spending (which include less than $1 million for remedy related capital costs) in the year ended December 31, 2015 is probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision.

(3) These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses.

(4) In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision and does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs are being expensed as incurred.

Other Legal and Regulatory Contingencies

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits.  In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations.  A provision for a loss contingency is recorded 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.  The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred.

Investigation of the Butte Fire

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. The California Department of Forestry and Fire Protection (“Cal Fire”) is investigating the source of the Butte Fire to determine whether a tree contacted a power line operated by the Utility and was the cause of the fire.  Cal Fire has reported that as a result of the fire there were two deaths and 965 structures, including 571 houses, were damaged or destroyed. Cal Fire’s investigation is expected to conclude in 2016.

Approximately 27 complaints have been filed against the Utility and its vegetation management contractors in the Superior Court of California in both the County of Calaveras and the County of San Francisco, involving more than 600 individual plaintiffs and their insurance companies. Plaintiffs and the Utility filed petitions with the California Judicial Council to coordinate these cases.  The petitions were assigned to the Calaveras Superior Court for a recommendation to the Judicial Council. On January 21, 2016, the Calaveras Superior Court issued an order recommending to the Judicial Council that the cases be coordinated in the Superior Court of California, Sacramento County, for all purposes including trial.  Among other factors, the Court found that coordination requires a court with a significant number of judges and complex litigation support personnel, neither of which are present in Calaveras County.

It is estimated that losses related to structures, contents, other personal property, and fire suppression costs associated with the Butte fire, will range from $350 million to $450 million.  This range is based on estimates about the number, size, and type of structures damaged or destroyed, assumptions about the contents of such structures and other personal property damage, and information about the amount of fire suppression costs associated with prior similar fires.  The Utility believes that it is reasonably possible that it would be liable for some or all of these and other costs, such as costs associated with tree damage, personal injury, business interruption losses, and other damages.  The Utility is unable to reasonably estimate these other costs at this time due to the limited information available.

The Utility has insurance coverage for these types of claims. If the amount of insurance is insufficient to cover the Utility's liability resulting from the Butte fire, or if insurance is otherwise unavailable, PG&E Corporation’s and the Utility’s financial condition or results of operations could be materially affected.

Rehearing of CPUC Decisions Approving Energy Efficiency Incentive Awards

On September 17, 2015, the CPUC issued an order granting TURN’s and the ORA’s long-standing applications for rehearing of the CPUC decisions that awarded energy efficiency incentive payments to the California investor-owned utilities for the 2006-2008 energy efficiency program cycle. Under the ratemaking mechanism applicable to the 2006-2008 program cycle, the maximum amount of incentives that the Utility could have earned (or the maximum amount that the Utility could have been required to reimburse customers) over the 2006-2008 program cycle was $180 million. The Utility was awarded a total of $104 million for the 2006-2008 program cycle. In the re-opened energy efficiency proceeding, the CPUC will evaluate whether incentives awarded to the California investor-owned utilities were just and reasonable, and whether any refunds are due.  The parties are required to submit proposals to resolve the issues in the proceeding by March 18, 2016. Comments on the proposals are due on April 8, 2016 and evidentiary hearings, if needed, would be held in July 2016. It is uncertain when the CPUC will issue a decision and whether the Utility will be required to refund amounts or incur other obligations related to the 2006-2008 program cycle. PG&E Corporation and the Utility believe it is reasonably possible that the Utility will be required to refund amounts or incur other obligations related to this matter, but they are unable to reasonably estimate the amount of such refunds or other obligations.

Other Contingencies

Accruals for other legal and regulatory contingencies (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters” and “Other Legal and Regulatory Contingencies”) totaled $63 million at December 31, 2015, and $55 million at December 31, 2014.  These amounts are included in other current liabilities in the Consolidated Balance Sheets.  The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

Environmental Remediation Contingencies

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 the 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 Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is composed of the following:

	Balance at
(in millions)	December 31, 2015		December 31, 2014
Topock natural gas compressor station (1)	$	300	$	291
Hinkley natural gas compressor station (1)		140		158
Former manufactured gas plant sites owned by the Utility or third parties		271		257
Utility-owned generation facilities (other than fossil fuel-fired),   other facilities, and third-party disposal sites		164		150
Fossil fuel-fired generation facilities and sites		94		98
Total environmental remediation liability	$	969	$	954

(1) See “Natural Gas Compressor Station Sites” below.

At December 31, 2015 the Utility expected to recover $695 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC.  One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites (including the Topock site) without a reasonableness review.  The Utility may incur environmental remediation costs that it does not seek to recover in rates, such as the costs associated with the Hinkley site.

Natural Gas Compressor Station 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 stations.  One of these stations is located near Hinkley, California and is referred to below as the “Hinkley site.”  Another station is located near Needles, California and is referred to below as the “Topock site.”  The Utility is also required to take measures to abate the effects of the contamination on the environment.

Hinkley Site

The Utility has been implementing interim remediation measures at the Hinkley site to reduce the mass of the chromium plume and to monitor and control movement of the plume.  The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the Regional Board. On November 4, 2015, the Regional Board adopted a final clean-up and abatement order to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts.  The final order states that the Utility must continue and improve its remediation efforts; define the boundaries of the chromium plume, and take other action.  Additionally, the final order requires setting plume capture requirements, requires establishing a monitoring and reporting program, and finalizes deadlines for the Utility to meet interim cleanup targets.  The clean-up and abatement order did not have a material impact on the Utility’s consolidated financial statements.

The Utility’s environmental remediation liability at December 31, 2015 reflects the Utility’s best estimate of probable future costs associated with its final remediation plan.Future costs will depend on many factors, including the extent of work to be performed to implement the final remediation plan and the Utility’s required time frame for remediation.  Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition and cash flows.

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California Department of Toxic Substances Control and the U.S. Department of the Interior.  In November 2015, the Utility submitted its final remediation design to the agencies for approval.  The Utility’s design proposes that the Utility construct an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium.  The DTSC is conducting an additional environmental review of the proposed design, and the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in July 2016.  After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in December 2016.  After the Utility modifies its design in response to the final report, the Utility plans to seek approval to begin construction of the new in-situ treatment system in early 2017. 

The Utility’s environmental remediation liability at December 31, 2015 reflects its best estimate of probable future costs associated with its final remediation plan.  Future costs will depend on many factors, including the extent of work to be performed to implement the final groundwater remedy and the Utility’s required time frame for remediation.  Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition and cash flows.

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 $1.9 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.  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 results of operations during the period in which they are recorded.

Nuclear Insurance

The Utility is a member of 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 if a nuclear event were to occur 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 $3.5 billion per nuclear incident and $2.8 billion per non-nuclear incident for Diablo Canyon.  Humboldt Bay Unit 3 has up to $131 million of coverage for nuclear and non-nuclear property damages.  If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment.  If NEIL were to exercise this assessment, as of December 31, 2015, the current maximum aggregate annual retrospective premium obligation for the Utility is approximately $60 million.

NEIL also provides 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 $3.5 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 $3.5 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 $13.5 billion. The Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon.  The balance of the $13.5 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors.  The Utility may be assessed up to $255 million per nuclear incident under this program, with payments in each year limited to a maximum of $38 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 September 10, 2018.

The Price-Anderson Act does not apply to 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.  The Utility has a separate 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 liability insurance.

Resolution of Remaining Chapter 11 Disputed Claims

Various electricity suppliers filed claims in the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers 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 California Power Exchange wholesale electricity markets during this period. 

At December 31, 2015, and December 31, 2014, the Consolidated Balance Sheets reflected $454 million and $434 million, respectively, in net Disputed claims and customer refunds, including both principal and interest.  At December 31, 2015 and 2014, the Utility held $228 million and $291 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 liability 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 liability, 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 liability and when such interest is paid.

While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers.  The Utility has 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.  Under these settlement agreements, 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.  Any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods.

In July 2014, a settlement agreement between the Utility and an electric supplier became effective, resolving a portion of the Utility’s net disputed claims and resulting in refunds to customers of $312 million.  No significant settlement agreements were reached in 2015.  The Utility is uncertain when and how the remaining net disputed claims liability will be resolved.

Purchase Commitments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2015:

	Power Purchase Agreements
	Renewable		Conventional				Natural		Nuclear
(in millions)	Energy		Energy		Other		Gas		Fuel		Total
2016	$	2,177	$	772	$	504	$	421	$	113	$	3,987
2017		2,201		787		380		150		100		3,618
2018		2,075		706		359		105		96		3,341
2019		2,087		694		290		105		98		3,274
2020		2,077		674		213		103		133		3,200
Thereafter		29,098		1,729		997		543		185		32,552
Total purchase
commitments	$	39,715	$	5,362	$	2,743	$	1,427	$	725	$	49,972

Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase 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.

Renewable Energy Power Purchase Agreements.  In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.  The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement.  The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow significantly.  As of December 31, 2015, renewable energy contracts expire at various dates between 2016 and 2043.

Conventional Energy Power Purchase Agreements.  The Utility has entered into many 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.  As of December 31, 2015, these power purchase agreements expire at various dates between 2016 and 2033.

Other Power Purchase Agreements.  The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law.  Several of these agreements are treated as capital leases.  At December 31, 2015 and 2014, net capital leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $54 million and $74 million including accumulated amortization of $147 million and $128 million, respectively.  The present value of the future minimum lease payments due under these agreements included $19 million and $20 million in Current Liabilities and $35 million and $54 million in Noncurrent Liabilities on the Consolidated Balance Sheet, respectively.  As of December 31, 2015, QF contracts in operation expire at various dates between 2016 and 2028.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The costs incurred for all power purchases and electric capacity amounted to $3.5 billion in 2015, $3.6 billion in 2014, and $3.0 billion in 2013.

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.  These agreements expire at various dates between 2016 and 2026.  In addition, the Utility has contracted for natural gas storage services in northern California in order to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $0.9 billion in 2015, $1.4 billion in 2014, and $1.6 billion in 2013.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2016 and 2025 and are intended to ensure long-term nuclear fuel supply.  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. 

Payments for nuclear fuel amounted to $128 million in 2015, $105 million in 2014, and $162 million in 2013.

Other Commitments

PG&E Corporation and the Utility have other commitments related to operating leases (primarily office facilities and land), which expire at various dates between 2016 and 2052.  At December 31, 2015, the future minimum payments related to these commitments were as follows:

(in millions)	Operating Leases
2016	$	40
2017		41
2018		40
2019		38
2020		37
Thereafter		194
Total minimum lease payments	$	390

Payments for other commitments related to operating leases amounted to $41million in 2015, $42 million in 2014, and $40 million in 2013.  Certain leases on office facilities contain escalation clauses requiring annual increases in rent.  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 operations ranging between one and five years.

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Schedule I - Condensed Financial Information Of Parent

12 Months Ended

Dec. 31, 2015

Schedule I - Condensed Financial Information Of Parent

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

		Years Ended December 31,
(in millions, except per share amounts)		2015		2014		2013
Administrative service revenue	$	51	$	51	$	41
Operating expenses		(53)		(53)		(42)
Interest income		1		1		1
Interest expense		(10)		(14)		(25)
Other income (expense)		30		(1)		(57)
Equity in earnings of subsidiaries		852		1,413		848
Income before income taxes		871		1,397		766
Income tax benefit		3		39		48
Net income	$	874	$	1,436	$	814
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $0,
$10, and $80, at respective dates)	$	(1)	$	(14)	$	113
Net change in investments (net of taxes of $12, $17, and $26, at respective dates)		(17)		(25)		38
Total other comprehensive income (loss)		(18)		(39)		151
Comprehensive Income	$	856	$	1,397	$	965
Weighted Average Common Shares Outstanding, Basic		484		468		444
Weighted Average Common Shares Outstanding, Diluted		487		470		445
Net earnings per common share, basic	$	1.81	$	3.07	$	1.83
Net earnings per common share, diluted	$	1.79	$	3.06	$	1.83

PG&E CORPORATION

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

CONDENSED BALANCE SHEETS

	Balance at December31,
(in millions)	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	64	$	96
Advances to affiliates		22		31
Income taxes receivable		24		29
Other		1		38
Total current assets		111		194
Noncurrent Assets
Equipment		2		2
Accumulated depreciation		(2)		(1)
Net equipment		-		1
Investments in subsidiaries		16,837		16,003
Other investments		130		117
Deferred income taxes		250		260
Total noncurrent assets		17,217		16,381
Total Assets	$	17,328	$	16,575
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable – other		3		67
Other		246		269
Total current liabilities		249		336
Noncurrent Liabilities
Long-term debt		350		350
Other		153		141
Total noncurrent liabilities		503		491
Common Shareholders’ Equity
Common stock		11,282		10,421
Reinvested earnings		5,301		5,316
Accumulated other comprehensive income (loss)		(7)		11
Total common shareholders’ equity		16,576		15,748
Total Liabilities and Shareholders’ Equity	$	17,328	$	16,575

PG&E CORPORATION

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

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2015		2014		2013
Cash Flows from Operating Activities:
Net income	$	874	$	1,436	$	814
Adjustments to reconcile net income to net cash provided by
operating activities:
Stock-based compensation amortization		66		65		54
Equity in earnings of subsidiaries		(852)		(1,413)		(848)
Deferred income taxes and tax credits-net		10		(72)		(10)
Noncurrent income taxes receivable/payable		-		5		-
Current income taxes receivable/payable		5		(16)		20
Other		(70)		43		(20)
Net cash provided by operating activities		33		48		10
Cash Flows From Investing Activities:
Investment in subsidiaries		(705)		(978)		(1,371)
Dividends received from subsidiaries (1)		716		716		716
Proceeds from tax equity investments		-		368		275
Other		-		-		(8)
Net cash provided by (used in) investing activities		11		106		(388)
Cash Flows From Financing Activities:
Borrowings (repayments) under revolving credit facilities		-		(260)		140
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $3 million		-		347		-
Repayments of long-term debt		-		(350)		-
Common stock issued		780		802		1,045
Common stock dividends paid(2)		(856)		(828)		(782)
Other		-		-		(1)
Net cash provided by (used in) financing activities		(76)		(289)		402
Net change in cash and cash equivalents		(32)		(135)		24
Cash and cash equivalents at January 1		96		231		207
Cash and cash equivalents at December 31	$	64	$	96	$	231
Supplemental disclosure of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(9)	$	(15)	$	(23)
Income taxes, net		-		1		21
Supplemental disclosure of noncash investing and financing activities
Noncash common stock issuances	$	21	$	21	$	22
Common stock dividends declared but not yet paid		224		217		208

(1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow.

(2) In January, April, July, and October of 2015, 2014, and 2013, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

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Schedule II - Consolidated Valuation And Qualifying Accounts

12 Months Ended

Dec. 31, 2015

Schedule II - Consolidated Valuation And Qualifying Accounts

PG&E Corporation

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2015, 2014, and 2013

(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:
2015:
Allowance for uncollectible accounts (1)	$	66	$	43	$	-	$	55	$	54
2014:
Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66
2013:
Allowance for uncollectible accounts (1)	$	87	$	53	$	-	$	60	$	80

(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, 2015, 2014, and 2013

(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:
2015:
Allowance for uncollectible accounts (1)	$	66	$	43	$	-	$	55	$	54
2014:
Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66
2013:
Allowance for uncollectible accounts (1)	$	87	$	53	$	-	$	60	$	80

(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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Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2015

Summary Of Significant Accounting Policies [Abstract]

Regulation And Regulated Operations

Regulation and Regulated Operations

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service.  The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  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.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.  In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income.  (See “Revenue Recognition” below.)

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.  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.

Revenue Recognition

Revenue Recognition

The Utility recognizes revenues when electricity and natural gas services are delivered.  The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements.

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, 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 that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, revenue is recognized ratably over the year.

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. In general, 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 periodic (often annual) TO 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.

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.  (See “Resolution of Remaining Chapter 11 Disputed Claims” in 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 uncollectable customer 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 and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.

Emission Allowances

Emission Allowances

The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.

Property, Plant, And Equipment

Property, Plant, and Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  (See “AFUDC” below.)  The Utility’s total 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)	2015		2014
Electricity generating facilities (1)	5 to 100	$	9,860		$	9,374
Electricity distribution facilities	15 to 55		28,476			26,633
Electricity transmission facilities	15 to 75		10,196			9,155
Natural gas distribution facilities	5 to 60		10,397			9,741
Natural gas transportation and storage facilities	5 to 65		6,352			5,937
Construction work in progress			2,059			2,220
Total property, plant, and equipment			67,340			63,060
Accumulated depreciation			(20,617)			(19,120)
Net property, plant, and equipment		$	46,723		$	43,940

(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 13 below.)

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 balance 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 3.80% in 2015, 3.77% in 2014, and 3.51% in 2013.  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 represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service 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 related to debt and equity, respectively, of $48 million and $107 million during 2015, $45 million and $100 million during 2014, and $47 million and $101 million during 2013.

Asset Retirement Obligations

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2015 and 2014, including nuclear decommissioning obligations:

(in millions)		2015		2014
ARO liability at beginning of year	$	3,575	$	3,538
Revision in estimated cash flows		13		(16)
Accretion		169		163
Liabilities settled		(114)		(110)
ARO liability at end of year	$	3,643	$	3,575

The Utility has not recorded a liability related to certain ARO’s for assets that are expected to operate in perpetuity.  As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made.  As such, ARO liabilities are not recorded for retirement activities associated with substations, photovoltaic facilities, and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration or land to the conditions under certain agreements.

Nuclear Decommissioning Obligation

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.

The Utility adjusts its nuclear decommissioning obligation to reflect changes in the estimated costs of decommissioning its nuclear power facilities and records this as an adjustment to the ARO liability on its Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued was $2.5 billion at December 31, 2015 and 2014.  The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $3.5 billion at December 31, 2015 and 2014 (or $6.1 billion in future dollars). These estimates are based on the 2012 decommissioning cost studies, prepared in accordance with CPUC requirements.

Disallowance of Plant Costs

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge 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.  The Utility recorded charges of $407 million in 2015 for estimated capital spending that is probable of disallowance related to the Penalty Decision and $116 million and $196 million in 2014 and 2013, respectively, for PSEP capital costs that are expected to exceed the CPUC’s authorized levels or that are specifically disallowed.  (See “Enforcement and Litigation Matters” in Note 13 below).

Nuclear Decommissioning Trusts

Nuclear Decommissioning Trusts

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one 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 by the trust is determined by specific identification.

Variable Interest Entities

Variable Interest Entities

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 that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate 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.  To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2015, it assessed 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, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities.  The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2015, it did not consolidate any of them.

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Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

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)	2015		2014
Electricity generating facilities (1)	5 to 100	$	9,860		$	9,374
Electricity distribution facilities	15 to 55		28,476			26,633
Electricity transmission facilities	15 to 75		10,196			9,155
Natural gas distribution facilities	5 to 60		10,397			9,741
Natural gas transportation and storage facilities	5 to 65		6,352			5,937
Construction work in progress			2,059			2,220
Total property, plant, and equipment			67,340			63,060
Accumulated depreciation			(20,617)			(19,120)
Net property, plant, and equipment		$	46,723		$	43,940

(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 13 below.)

Schedule Of Changes In Asset Retirement Obligations

(in millions)		2015		2014
ARO liability at beginning of year	$	3,575	$	3,538
Revision in estimated cash flows		13		(16)
Accretion		169		163
Liabilities settled		(114)		(110)
ARO liability at end of year	$	3,643	$	3,575

Reclassification Out Of Accumulated Other Comprehensive Income TableText Block

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2015 consisted of the following:

	Pension		Other			Other
(in millions, net of income tax)	Benefits		Benefits			Investments			Total
Beginning balance	$	(21)		$	15		$	17		$	11
Other comprehensive income before reclassifications:
Unrecognized net actuarial loss
(net of taxes of $51, $21, and $0, respectively)		(76)			(31)			-			(107)
Regulatory account transfer
(net of taxes of $51, $21, and $0, respectively)		73			31			-			104
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $7, $8, and $0, respectively) (1)		8			11			-			19
Amortization of net actuarial loss
(net of taxes of $4, $1, and $0, respectively) (1)		6			3			-			9
Regulatory account transfer
(net of taxes of $10, $9, and $0, respectively) (1)		(13)			(13)			-			(26)
Realized gain on investments
(net of taxes of $0, $0, and $12, respectively)		-			-			(17)			(17)
Net current period other comprehensive loss		(2)			1			(17)			(18)
Ending balance	$	(23)		$	16		$	-		$	(7)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2014 consisted of the following:

	Pension		Other			Other
(in millions, net of income tax)	Benefits		Benefits			Investments			Total
Beginning balance	$	(7)		$	15		$	42		$	50
Other comprehensive income before reclassifications:
Change in investments
(net of taxes of $0, $0, and $4, respectively)		-			-			5			5
Unrecognized net actuarial loss
(net of taxes of $404, $19, and $0, respectively)		(588)			(28)			-			(616)
Unrecognized prior service cost
(net of taxes of $0, $0, and $0, respectively)		1			-			-			1
Regulatory account transfer
(net of taxes of $394, $19, and $0, respectively)		573			28			-			601
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $8, $9, and $0, respectively) (1)		12			14			-			26
Amortization of net actuarial loss
(net of taxes of $1, $1, and $0, respectively) (1)		1			1			-			2
Regulatory account transfer
(net of taxes of $9, $10, and $0, respectively) (1)		(13)			(15)			-			(28)
Realized gain on investments
(net of taxes of $0, $0, and $20, respectively)		-			-			(30)			(30)
Net current period other comprehensive loss		(14)			-			(25)			(39)
Ending balance	$	(21)		$	15		$	17		$	11

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)

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Regulatory Assets, Liabilities, And Balancing Accounts (Tables)

12 Months Ended

Dec. 31, 2015

Regulatory Assets, Liabilities, And Balancing Accounts [Abstract]

Long-Term Regulatory Assets

	Balance at December 31,					Recovery
(in millions)	2015		2014			Period
Pension benefits (1)	$	2,414	$	2,347	Indefinitely (4)
Deferred income taxes (1)		3,054		2,390	47 years
Utility retained generation (2)		411		456	10 years
Environmental compliance costs (1)		748		717	32 years
Price risk management (1)		138		127	10 years
Electromechanical meters (3)		-		70	-
Unamortized loss, net of gain, on reacquired debt (1)		94		113	11 years
Other		170		102	Various
Total long-term regulatory assets	$	7,029	$	6,322

(1) Represents the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP.

(2) 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, 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. 

(3) Represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices. As of December 31, 2015, the remaining balance of $70 million is included in current regulatory assets on the Consolidated Balance Sheets.

(4) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.

Long-Term Regulatory Liabilities

	Balance at December 31,
(in millions)	2015		2014
Cost of removal obligations (1)	$	4,605	$	4,211
Recoveries in excess of AROs (2)		631		754
Public purpose programs (3)		600		701
Other		485		624
Total long-term regulatory liabilities	$	6,321	$	6,290

(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.

(2) Represents the cumulative differences between ARO expenses and amounts collected in rates.  Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments.  (See Note 10 below.)

(3) 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.

Current Regulatory Balancing Accounts Receivable

	Receivable
	Balance at December 31,
(in millions)	2015		2014
Electric distribution	$	380	$	344
Utility generation		122		261
Gas distribution		493		566
Energy procurement		262		608
Public purpose programs		155		109
Other		348		378
Total regulatory balancing accounts receivable	$	1,760	$	2,266

Current Regulatory Balancing Accounts Payable

	Payable
	Balance at December 31,
(in millions)	2015		2014
Energy procurement	$	112	$	188
Public purpose programs		244		154
Other		359		748
Total regulatory balancing accounts payable	$	715	$	1,090

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Debt (Tables)

12 Months Ended

Dec. 31, 2015

Debt [Abstract]

Schedule Of Long-Term Debt

	December 31,
(in millions)	2015		2014
PG&E Corporation
Senior notes, 2.40%, due 2019		350		350
Total PG&E Corporation long-term debt		350		350
Utility
Senior notes:
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		400
3.25% due 2023		375		375
3.85% due 2023		300		300
3.40% due 2024		350		350
3.75% due 2024		450		450
3.50% due 2025		600		-
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		400
3.75% due 2042		350		350
4.60% due 2043		375		375
5.125% due 2043		500		500
4.75% due 2044		675		675
4.30% due 2045		600		500
4.25% due 2046		450		-
Unamortized discount, net of premium		(53)		(43)
Total senior notes, net of current portion		14,572		13,432
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 (1), due 2016 and 2026 (4)		309		309
Less: current portion		(160)		-
Total pollution control bonds		1,108		1,268
Total Utility long-term debt, net of current portion		15,680		14,700
Total consolidated long-term debt, net of current portion	$	16,030	$	15,050

(1) At December 31, 2015, interest rates on these bonds were 0.01%.

(2) Each series of these bonds is supported by a separate letter of credit.  In December 2015, the letters of credit were extended to December 1, 2020.  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) Each series of these bonds is supported by a separate direct-pay letter of credit. Series C and D letters of credit expire on December 3, 2016 to coincide with the maturity of the underlying bonds.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.

Schedule Of Short-Term Borrowings

		Credit			Letters of			Commercial
	Termination	Facility			Credit			Paper			Facility
(in millions)	Date	Limit			Outstanding			Outstanding			Availability
PG&E Corporation	April 2020	$	300	(1)		$	-		$	-		$	300
Utility	April 2020		3,000	(2)			33			1,019			1,948
Total revolving credit facilities		$	3,300			$	33		$	1,019		$	2,248

(1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

(2) Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans.

Schedule Of Repayment Schedule

(in millions,
except interest rates)	2016			2017				2018				2019				2020				Thereafter				Total
PG&E Corporation
Average fixed interest rate		-				-				-				2.40	%			-				-				2.40
Fixed rate obligations	$	-			$	-			$	-			$	350			$	-			$	-			$	350
Utility
Average fixed interest rate		-				5.63	%			8.25	%			-				3.50	%			4.91	%			5.05
Fixed rate obligations	$	-			$	700			$	800			$	-			$	800			$	12,670			$	14,970
Variable interest rate
as of December 31, 2015		0.01	%			-				-				0.01	%			0.01	%			-				0.01
Variable rate obligations (1)	$	160			$	-			$	-			$	149			$	614			$	-			$	923
Total consolidated debt	$	160			$	700			$	800			$	499			$	1,414			$	12,670			$	16,243

(1) These bonds, due in 2016 and 2026, are backed by separate letters of credit that expire on December 3, 2016, June 5, 2019, or December 1, 2020.

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Common Stock And Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2015

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule Of Compensation Expense For Share-Based Incentive Awards

(in millions)	2015		2014		2013
Restricted stock units	$	47	$	42	$	36
Performance shares		46		36		28
Total compensation expense (pre-tax)	$	93	$	78	$	64
Total compensation expense (after-tax)	$	55	$	47	$	38

Schedule Of Restricted Stock Units

The following table summarizes restricted stock unit activity for 2015:

	Number of	Weighted Average Grant-
	Restricted Stock Units	Date Fair Value
Nonvested at January 1	2,538,357	$	43.39
Granted	820,834	$	53.30
Vested	(1,304,150)	$	43.51
Forfeited	(82,142)	$	45.63
Nonvested at December 31	1,972,899	$	47.33

Schedule Of Performance Shares

The following table summarizes activity for performance shares in 2015:

	Number of	Weighted Average Grant-
	Performance Shares	Date Fair Value
Nonvested at January 1	1,693,939	$	42.37
Granted	669,519		68.27
Vested	(421,262)		33.57
Forfeited (1)	(491,584)		35.56
Nonvested at December 31	1,450,612	$	59.24
(1) Includes performance shares that expired with 50% value as a result of total shareholder return results.

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2015

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)	2015		2014		2013
Income available for common shareholders	$	874	$	1,436	$	814
Weighted average common shares outstanding, basic		484		468		444
Add incremental shares from assumed conversions:
Employee share-based compensation		3		2		1
Weighted average common share outstanding, diluted		487		470		445
Total earnings per common share, diluted	$	1.79	$	3.06	$	1.83

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Taxes [Abstract]

Schedule Of Components Of Income Tax Expense (Benefit)

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2015		2014		2013		2015		2014		2013
Current:
Federal	$	(89)	$	(84)	$	(218)	$	(88)	$	(84)	$	(222)
State		11		(41)		(26)		6		(29)		(23)
Deferred:
Federal		131		396		552		136		426		604
State		(76)		78		(35)		(69)		75		(28)
Tax credits		(4)		(4)		(5)		(4)		(4)		(5)
Income tax provision	$	(27)	$	345	$	268	$	(19)	$	384	$	326

Schedule Of Deferred Tax Assets And Liabilities

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2015		2014		2015		2014
Deferred income tax assets:
Customer advances for construction	$	69	$	88	$	69	$	88
Environmental reserve		85		111		85		111
Compensation and benefits		219		244		145		173
Tax carryforwards		1,703		1,177		1,462		946
Greenhouse gas allowances		340		56		340		56
Other		44		74		61		100
Total deferred income tax assets	$	2,460	$	1,750	$	2,162	$	1,474
Deferred income tax liabilities:
Regulatory balancing accounts	$	691	$	512	$	691	$	512
Property related basis differences		9,656		8,683		9,638		8,666
Income tax regulatory asset (1)		1,244		974		1,245		974
Other		75		88		75		86
Total deferred income tax liabilities	$	11,666	$	10,257	$	11,649	$	10,238
Total net deferred income tax liabilities	$	9,206	$	8,507	$	9,487	$	8,764
Classification of net deferred income tax liabilities:
Included in current liabilities (assets)	$	-	$	(6)	$	-	$	(9)
Included in noncurrent liabilities		9,206		8,513		9,487		8,773
Total net deferred income tax liabilities	$	9,206	$	8,507	$	9,487	$	8,764

(1)Represents the deferred income tax component of the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP.  (See Note 3 above.)

Schedule Of Effective Income Tax Rate Reconciliation

	PG&E Corporation										Utility
	Year Ended December 31,
	2015			2014			2013			2015				2014			2013
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) (1)	(4.9)		1.4			(3.1)			(4.8)				1.6			(2.2)
Effect of regulatory treatment
of fixed asset differences (2)	(33.6)		(15.0)			(4.2)			(33.7)				(14.7)			(3.8)
Tax credits	(1.3)		(0.7)			(0.4)			(1.3)				(0.7)			(0.4)
Benefit of loss carryback	(1.5)		(0.8)			(1.1)			(1.5)				(0.8)			(1.0)
Non deductible penalties (3)	4.3		0.3			0.8			4.3				0.3			0.7
Other, net	(1.1)		(0.8)			(2.2)			(0.2)				0.4			(0.9)
Effective tax rate	(3.1)	%	19.4		%	24.8		%	(2.2)			%	21.1		%	27.4		%

(1)Includes the effect of state flow-through ratemaking treatment.  In 2015, amounts include an agreement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions.   

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs in 2015 and 2014 as authorized by the 2014 GRC decision.  Amounts are impacted by the level of income before income taxes. 

(3) Represents the effects of non-tax deductible fines and penalties associated with the Penalty Decision.  (For more information about the Penalty Decision see Note 13 below.)

Schedule Of Change In Unrecognized Tax Benefits

	PG&E Corporation						Utility
(in millions)	2015		2014		2013		2015		2014		2013
Balance at beginning of year	$	713	$	666	$	581	$	707	$	660	$	575
Additions for tax position taken
during a prior year		40		7		12		40		7		12
Reductions for tax position
taken during a prior year		(349)		(9)		(6)		(349)		(9)		(6)
Additions for tax position
taken during the current year		64		61		79		64		61		79
Settlements		-		(12)		-		-		(12)		-
Balance at end of year	$	468	$	713	$	666	$	462	$	707	$	660

Schedule of Operating Loss And Tax Credit Carryforward Balances

	December 31,		Expiration
(in millions)	2015		Year
Federal:
Net operating loss carryforward	$	4,856	2029 - 2035
Tax credit carryforward		110	2029 - 2035
Charitable contribution loss carryforward		178	2017 - 2020
State:
Net operating loss carryforward	$	80	2033 - 2034
Tax credit carryforward		59	Various
Charitable contribution loss carryforward		119	2019 - 2020

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Derivatives And Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2015

Derivatives And Hedging Activities [Abstract]

Volumes Of Outstanding Derivative Contracts

		Contract Volume
Underlying Product	Instruments	2015	2014
Natural Gas (1) (MMBtus (2))	Forwards and Swaps	333,091,813	308,130,101
	Options	111,550,004	164,418,002
Electricity (Megawatt-hours)	Forwards and Swaps	3,663,512	5,346,787
	Congestion Revenue Rights (3)	216,383,389	224,124,341

(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.

(2) Million British Thermal Units.

(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Outstanding Derivative Balances

At December 31, 2015, 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	$	97	$		(4)	$		25	$		118
Other noncurrent assets – other		172			(2)			-			170
Current liabilities – other		(102)			4			44			(54)
Noncurrent liabilities – other		(140)			2			21			(117)
Total commodity risk	$	27	$		-	$		90	$		117

At December 31, 2014, 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	$	73	$		(4)	$		19	$		88
Other noncurrent assets – other		178			(13)			-			165
Current liabilities – other		(78)			4			26			(48)
Noncurrent liabilities – other		(140)			13			9			(118)
Total commodity risk	$	33	$		-	$		54	$		87

Gains And Losses On Derivative Instruments

	Commodity Risk
	For the year ended December 31,
(in millions)	2015		2014		2013
Unrealized gain/(loss) - regulatory assets and liabilities (1)	$	(6)	$	124	$	238
Realized loss - cost of electricity (2)		(14)		(83)		(178)
Realized loss - cost of natural gas (2)		(10)		(8)		(22)
Total commodity risk	$	(30)	$	33	$	38

(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, 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)	2015		2014
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(2)	$	(47)
Related derivatives in an asset position		-		-
Collateral posting in the normal course of business related to
these derivatives		-		44
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(2)	$	(3)

(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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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Measurements [Abstract]

Assets And Liabilities Measured At Fair Value On A Recurring Basis

	Fair Value Measurements
	At December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	64	$	-	$	-	$	-	$	64
Nuclear decommissioning trusts
Money market investments		36		-		-		-		36
Global equity securities		1,520		13		-		-		1,533
Fixed-income securities		694		521		-		-		1,215
Total nuclear decommissioning trusts (2)		2,250		534		-		-		2,784
Price risk management instruments
(Note 9)
Electricity		-		9		259		18		286
Gas		-		1		-		1		2
Total price risk management
instruments		-		10		259		19		288
Rabbi trusts
Fixed-income securities		-		57		-		-		57
Life insurance contracts		-		70		-		-		70
Total rabbi trusts		-		127		-		-		127
Long-term disability trust
Money market investments		7		-		-		-		7
Global equity securities		-		26		-		-		26
Fixed-income securities		-		132		-		-		132
Total long-term disability trust		7		158		-		-		165
Total assets	$	2,321	$	829	$	259	$	19	$	3,428
Liabilities:
Price risk management instruments
(Note 9)
Electricity	$	69	$	1	$	170	$	(70)	$	170
Gas		-		2		-		(1)		1
Total liabilities	$	69	$	3	$	170	$	(71)	$	171

(1)Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $314 million, primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2014
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	94	$	-	$	-	$	-	$	94
Nuclear decommissioning trusts
Money market investments		17		-		-		-		17
Global equity securities		1,585		13		-		-		1,598
Fixed-income securities		741		389		-		-		1,130
Total nuclear decommissioning trusts (2)		2,343		402		-		-		2,745
Price risk management instruments
(Note 9)
Electricity		-		17		232		2		251
Gas		1		1		-		-		2
Total price risk management
instruments		1		18		232		2		253
Rabbi trusts
Fixed-income securities		-		42		-		-		42
Life insurance contracts		-		72		-		-		72
Total rabbi trusts		-		114		-		-		114
Long-term disability trust
Money market investments		7		-		-		-		7
Global equity securities		-		25		-		-		25
Fixed-income securities		-		128		-		-		128
Total long-term disability trust		7		153		-		-		160
Other investments		33		-		-		-		33
Total assets	$	2,478	$	687	$	232	$	2	$	3,399
Liabilities:
Price risk management instruments
(Note 9)
Electricity	$	47	$	5	$	163	$	(52)	$	163
Gas		-		3		-		-		3
Total liabilities	$	47	$	8	$	163	$	(52)	$	166

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $324 million, primarily related to deferred taxes on appreciation of investment value.

Sensitivity Analysis

	Fair Value at
(in millions)	At December 31, 2015				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	259	$	63	Market approach	CRR auction prices	$	(161.36) - 8.76
Power purchase agreements	$	-	$	107	Discounted cash flow	Forward prices	$	15.08 - 37.27

1. Represents price per megawatt-hour

	Fair Value at
(in millions)	At December 31, 2014				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	232	$	63	Market approach	CRR auction prices	$	(15.97) - 8.17
Power purchase agreements	$	-	$	100	Discounted cash flow	Forward prices	$	16.04 - 56.21

(1) Represents price per megawatt-hour

Level 3 Reconciliation

	Price Risk Management Instruments
(in millions)	2015		2014
Asset (liability) balance as of January 1	$	69		$	(30)
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		20			99
Asset (liability) balance as of December 31	$	89		$	69

    (1) The costs related to 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,
	2015					2014
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount			Level 2 Fair Value
Debt (Note 4)
PG&E Corporation	$	350	$	354	$		350	$	352
Utility		14,918		16,422			13,778		15,851

Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments

				Total		Total
	Amortized			Unrealized		Unrealized		Total Fair
(in millions)	Cost			Gains		Losses		Value
As of December 31, 2015
Nuclear decommissioning trusts
Money market investments	$	36	$	-	$	-	$	36
Global equity securities		508		1,034		(9)		1,533
Fixed-income securities		1,165		58		(8)		1,215
Total (1)	$	1,709	$	1,092	$	(17)	$	2,784
As of December 31, 2014
Nuclear decommissioning trusts
Money market investments	$	17	$	-	$	-	$	17
Global equity securities		520		1,087		(9)		1,598
Fixed-income securities		1,059		75		(4)		1,130
Total nuclear decommissioning trusts (1)		1,596		1,162		(13)		2,745
Other investments		5		28		-		33
Total	$	1,601	$	1,190	$	(13)	$	2,778

(1) Represents amounts before deducting $314 million and $324 million at December 31, 2015 and 2014, respectively, primarily related to deferred taxes on appreciation of investment value.

Schedule Of Long Term Debt Repayments

	As of
(in millions)	December 31, 2015
Less than 1 year	$	18
1–5 years		470
5–10 years		273
More than 10 years		454
Total maturities of debt securities	$	1,215

Schedule Of Activity For Debt And Equity Securities

	2015		2014		2013
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust
investments	$	1,268	$	1,336	$	1,619
Gross realized gains on sales of securities held as available-for-sale		55		118		94
Gross realized losses on sales of securities held as available-for-sale		(37)		(12)		(13)

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2015

Defined Benefit Plan Disclosure [Line Items]

Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status

Pension Plan

(in millions)	2015		2014
Change in plan assets:
Fair value of plan assets at beginning of year	$	14,216		$	12,527
Actual return on plan assets		(176)			1,946
Company contributions		334			332
Benefits and expenses paid		(629)			(589)
Fair value of plan assets at end of year	$	13,745		$	14,216
Change in benefit obligation:
Benefit obligation at beginning of year	$	16,696		$	14,077
Service cost for benefits earned		479			383
Interest cost		673			695
Actuarial (gain) loss		(922)			2,131
Plan amendments		1			(1)
Transitional costs		1			-
Benefits and expenses paid		(629)			(589)
Benefit obligation at end of year (1)	$	16,299		$	16,696
Funded Status:
Current liability	$	(6)		$	(6)
Noncurrent liability		(2,547)			(2,474)
Net liability at end of year	$	(2,553)		$	(2,480)

(1)PG&E Corporation’s accumulated benefit obligation was $14.7billion and $14.9 billion at December 31, 2015 and 2014, respectively.

Postretirement Benefits Other than Pensions

(in millions)	2015		2014
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,092		$	1,892
Actual return on plan assets		(26)			241
Company contributions		61			57
Plan participant contribution		68			63
Benefits and expenses paid		(160)			(161)
Fair value of plan assets at end of year	$	2,035		$	2,092
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,811		$	1,597
Service cost for benefits earned		55			45
Interest cost		71			76
Actuarial (gain) loss		(98)			166
Transitional costs		1			-
Benefits and expenses paid		(146)			(140)
Federal subsidy on benefits paid		4			4
Plan participant contributions		68			63
Benefit obligation at end of year	$	1,766		$	1,811
Funded Status: (1)
Noncurrent asset	$	344		$	368
Noncurrent liability		(75)			(87)
Net asset at end of year	$	269		$	281

(1) At December 31, 2015 and 2014, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.

Components Of Net Periodic Benefit Cost

Pension Plan

(in millions)	2015		2014			2013
Service cost	$	479		$	383		$	468
Interest cost		673			695			627
Expected return on plan assets		(873)			(807)			(650)
Amortization of prior service cost		15			20			20
Amortization of net actuarial loss		10			2			111
Net periodic benefit cost		304			293			576
Less: transfer to regulatory account (1)		34			42			(238)
Total expense recognized	$	338		$	335		$	338

(1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.

Postretirement Benefits Other than Pensions

(in millions)	2015		2014			2013
Service cost	$	55		$	45		$	53
Interest cost		71			76			74
Expected return on plan assets		(112)			(103)			(79)
Amortization of prior service cost		19			23			23
Amortization of net actuarial loss		4			2			6
Net periodic benefit cost	$	37		$	43		$	77

Estimated Amortized Net Periodic Benefit For 2012

(in millions)	Pension Plan		PBOP Plans
Unrecognized prior service cost	$	8	$	15
Unrecognized net loss		24		4
Total	$	32	$	19

Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost

	Pension Plan						PBOP Plans
	December 31,						December 31,
	2015		2014		2013		2015		2014		2013
Discount rate	4.37	%	4.00	%	4.89	%	4.27 - 4.48	%	3.89 - 4.09	%	4.70 - 5.00	%
Rate of future compensation
increases	4.00	%	4.00	%	4.00	%	-		-		-
Expected return on plan
assets	6.10	%	6.20	%	6.50	%	3.20 - 6.60	%	3.30 - 6.70	%	3.50 - 6.70	%

Schedule Of Assumed Health Care Cost Trend

The assumed health care cost trend rate as of December 31, 2015 was 7.2%, decreasing gradually to an ultimate trend rate in 2024 and beyond of approximately 4%.  A one-percentage-point change in assumed health care cost trend rate would have the following effects:

	One-Percentage-Point		One-Percentage-Point
(in millions)	Increase		Decrease
Effect on postretirement benefit obligation	$	113	$	(114)
Effect on service and interest cost		9		(9)

Target Asset Allocation Percentages

	Pension Plan								PBOP Plans
	2016		2015			2014			2016			2015			2014
Global equity	25	%		25	%		25	%		32	%		31	%		30	%
Absolute return	5	%		5	%		5	%		3	%		3	%		3	%
Real assets	10	%		10	%		10	%		7	%		8	%		8	%
Fixed income	60	%		60	%		60	%		58	%		58	%		59	%
Total	100	%		100	%		100	%		100	%		100	%		100	%

Schedule Of Changes In Fair Value Of Plan Assets

	Fair Value Measurements
	At December 31,
	2015												2014
(in millions)	Level 1			Level 2			Level 3			Total				Level 1			Level 2			Level 3			Total
Pension Plan:
Short-term investments	$	247	$		369	$		-	$		616	$			352	$		311	$		-	$		663
Global equity		903			2,243			-			3,146				918			2,311			-			3,229
Absolute return		-			-			660			660				-			-			577			577
Real assets		581			-			753			1,334				620			-			675			1,295
Fixed-income		1,841			5,516			640			7,997				2,068			5,718			638			8,424
Total	$	3,572	$		8,128	$		2,053	$		13,753	$			3,958	$		8,340	$		1,890	$		14,188
PBOP Plans:
Short-term investments	$	20	$		-	$		-	$		20	$			28	$		-	$		-	$		28
Global equity		104			545			-			649				124			549			-			673
Absolute return		-			-			65			65				-			-			55			55
Real assets		69			-			77			146				72			-			49			121
Fixed-income		150			1,010			-			1,160				163			1,055			1			1,219
Total	$	343	$		1,555	$		142	$		2,040	$			387	$		1,604	$		105	$		2,096
Total plan assets at fair value									$		15,793											$		16,284

Schedule Of Level 3 Reconciliation

	Pension Plan
(in millions)	Absolute		Fixed-
For the year ended December 31, 2015	Return		Income		Real Assets		Total
Balance at beginning of year	$	577	$	638	$	675	$	1,890
Actual return on plan  assets:
Relating to assets still held at the reporting date		(7)		9		63		65
Relating to assets sold during the period		-		1		-		1
Purchases, issuances, sales, and settlements:
Purchases		90		2		17		109
Settlements		-		(10)		(2)		(12)
Balance at end of year	$	660	$	640	$	753	$	2,053
	Pension Plan
(in millions)	Absolute		Fixed-
For the year ended December 31, 2014	Return		Income		Real Assets		Total
Balance at beginning of year	$	554	$	625	$	544	$	1,723
Actual return on plan assets:
Relating to assets still held at the reporting date		23		24		54		101
Relating to assets sold during the period		-		4		-		4
Purchases, issuances, sales, and settlements:
Purchases		-		1		78		79
Settlements		-		(16)		(1)		(17)
Balance at end of year	$	577	$	638	$	675	$	1,890

	PBOP Plans
(in millions)	Absolute			Fixed-
For the year ended December 31, 2015	Return			Income			Real Assets			Total
Balance at beginning of year	$	55	$		1	$		49	$		105
Actual return on plan  assets:
Relating to assets still held at the reporting date		(1)			-			5			4
Relating to assets sold during the period		-			-			-			-
Purchases, issuances, sales, and settlements:
Purchases		11			-			23			34
Settlements		-			(1)			-			(1)
Balance at end of year	$	65	$		-	$		77	$		142
	PBOP Plans
(in millions)	Absolute			Fixed-
For the year ended December 31, 2014	Return			Income			Real Assets			Total
Balance at beginning of year	$	53	$		2	$		38	$		93
Actual return on plan assets:
Relating to assets still held at the reporting date		2			-			4			6
Relating to assets sold during the period		-			-			-			-
Purchases, issuances, sales, and settlements:
Purchases		-			-			7			7
Settlements		-			(1)			-			(1)
Balance at end of year	$	55	$		1	$		49	$		105

Schedule Of Estimated Benefits Expected To Be Paid

	Pension		PBOP			Federal
(in millions)	Plan		Plans			Subsidy
2016	$	695		$	89		$	(6)
2017		739			95			(7)
2018		780			101			(7)
2019		818			107			(8)
2020		854			113			(8)
Thereafter in the succeeding five years		4,728			593			(17)

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Related Party Agreements And Transactions (Tables)

12 Months Ended

Dec. 31, 2015

Related Party Agreements And Transactions [Abstract]

Schedule Of Significant Related Party Transactions

	Year Ended December 31,
(in millions)	2015		2014		2013
Utility revenues from:
Administrative services provided to PG&E Corporation	$	6	$	5	$	7
Utility expenses from:
Administrative services received from PG&E Corporation	$	53	$	54	$	45
Utility employee benefit due to PG&E Corporation		82		70		57

XML

Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments And Contingencies [Abstract]

Impact Of The Penalty Decision

	Year		Cumulative		Future
	Ended		Charges		Charges
		December 31,		December 31,	and		Total
(in millions)	2015		2015		Costs		Amount
Fine payable to the state (1)	$	100	$	300	$	-	$	300
Customer bill credit		400		400		-		400
Charge for disallowed capital (2)		407		407		282		689
Disallowed revenue for pipeline safety
expenses (3)		-		-		161		161
CPUC estimated cost of other remedies (4)		-		-		-		50
Total Penalty Decision fines and remedies	$	907	$	1,107	$	473	$	1,600

(1) In March 2015, the Utility increased its accrual from $200 million at December 31, 2014 to $300 million.

(2) The Penalty Decision prohibits the Utility from recovering certain expenses and capital spending associated with pipeline safety-related projects and programs that the CPUC will identify in the final decision to be issued in the Utility’s 2015 GT&S rate case.The Utility estimates that approximately $407 million of capital spending (which include less than $1 million for remedy related capital costs) in the year ended December 31, 2015 is probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision.

(3) These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses.

(4) In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision and does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs are being expensed as incurred.

Schedule of Environmental Remediation Liability

	Balance at
(in millions)	December 31, 2015		December 31, 2014
Topock natural gas compressor station (1)	$	300	$	291
Hinkley natural gas compressor station (1)		140		158
Former manufactured gas plant sites owned by the Utility or third parties		271		257
Utility-owned generation facilities (other than fossil fuel-fired),   other facilities, and third-party disposal sites		164		150
Fossil fuel-fired generation facilities and sites		94		98
Total environmental remediation liability	$	969	$	954

(1) See “Natural Gas Compressor Station Sites” below.

Schedule Of Undiscounted Future Expected Power Purchase Agreement Payments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2015:

	Power Purchase Agreements
	Renewable		Conventional				Natural		Nuclear
(in millions)	Energy		Energy		Other		Gas		Fuel		Total
2016	$	2,177	$	772	$	504	$	421	$	113	$	3,987
2017		2,201		787		380		150		100		3,618
2018		2,075		706		359		105		96		3,341
2019		2,087		694		290		105		98		3,274
2020		2,077		674		213		103		133		3,200
Thereafter		29,098		1,729		997		543		185		32,552
Total purchase
commitments	$	39,715	$	5,362	$	2,743	$	1,427	$	725	$	49,972

Schedule of Future Minimum Payments For Operating Leases

PG&E Corporation and the Utility have other commitments related to operating leases (primarily office facilities and land), which expire at various dates between 2016 and 2052.  At December 31, 2015, the future minimum payments related to these commitments were as follows:

(in millions)	Operating Leases
2016	$	40
2017		41
2018		40
2019		38
2020		37
Thereafter		194
Total minimum lease payments	$	390

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Schedule I - Condensed Financial Information Of Parent (Tables)

12 Months Ended

Dec. 31, 2015

Schedule I - Condensed Financial Information Of Parent [Abstract]

Schedule of Condensed Statements of Income

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

		Years Ended December 31,
(in millions, except per share amounts)		2015		2014		2013
Administrative service revenue	$	51	$	51	$	41
Operating expenses		(53)		(53)		(42)
Interest income		1		1		1
Interest expense		(10)		(14)		(25)
Other income (expense)		30		(1)		(57)
Equity in earnings of subsidiaries		852		1,413		848
Income before income taxes		871		1,397		766
Income tax benefit		3		39		48
Net income	$	874	$	1,436	$	814
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $0,
$10, and $80, at respective dates)	$	(1)	$	(14)	$	113
Net change in investments (net of taxes of $12, $17, and $26, at respective dates)		(17)		(25)		38
Total other comprehensive income (loss)		(18)		(39)		151
Comprehensive Income	$	856	$	1,397	$	965
Weighted Average Common Shares Outstanding, Basic		484		468		444
Weighted Average Common Shares Outstanding, Diluted		487		470		445
Net earnings per common share, basic	$	1.81	$	3.07	$	1.83
Net earnings per common share, diluted	$	1.79	$	3.06	$	1.83

Schedule of Condensed Balance Sheet

PG&E CORPORATION

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

CONDENSED BALANCE SHEETS

	Balance at December31,
(in millions)	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	64	$	96
Advances to affiliates		22		31
Income taxes receivable		24		29
Other		1		38
Total current assets		111		194
Noncurrent Assets
Equipment		2		2
Accumulated depreciation		(2)		(1)
Net equipment		-		1
Investments in subsidiaries		16,837		16,003
Other investments		130		117
Deferred income taxes		250		260
Total noncurrent assets		17,217		16,381
Total Assets	$	17,328	$	16,575
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable – other		3		67
Other		246		269
Total current liabilities		249		336
Noncurrent Liabilities
Long-term debt		350		350
Other		153		141
Total noncurrent liabilities		503		491
Common Shareholders’ Equity
Common stock		11,282		10,421
Reinvested earnings		5,301		5,316
Accumulated other comprehensive income (loss)		(7)		11
Total common shareholders’ equity		16,576		15,748
Total Liabilities and Shareholders’ Equity	$	17,328	$	16,575

Schedule Of Condensed Statement Of Cash Flows

PG&E CORPORATION

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

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2015		2014		2013
Cash Flows from Operating Activities:
Net income	$	874	$	1,436	$	814
Adjustments to reconcile net income to net cash provided by
operating activities:
Stock-based compensation amortization		66		65		54
Equity in earnings of subsidiaries		(852)		(1,413)		(848)
Deferred income taxes and tax credits-net		10		(72)		(10)
Noncurrent income taxes receivable/payable		-		5		-
Current income taxes receivable/payable		5		(16)		20
Other		(70)		43		(20)
Net cash provided by operating activities		33		48		10
Cash Flows From Investing Activities:
Investment in subsidiaries		(705)		(978)		(1,371)
Dividends received from subsidiaries (1)		716		716		716
Proceeds from tax equity investments		-		368		275
Other		-		-		(8)
Net cash provided by (used in) investing activities		11		106		(388)
Cash Flows From Financing Activities:
Borrowings (repayments) under revolving credit facilities		-		(260)		140
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $3 million		-		347		-
Repayments of long-term debt		-		(350)		-
Common stock issued		780		802		1,045
Common stock dividends paid(2)		(856)		(828)		(782)
Other		-		-		(1)
Net cash provided by (used in) financing activities		(76)		(289)		402
Net change in cash and cash equivalents		(32)		(135)		24
Cash and cash equivalents at January 1		96		231		207
Cash and cash equivalents at December 31	$	64	$	96	$	231
Supplemental disclosure of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(9)	$	(15)	$	(23)
Income taxes, net		-		1		21
Supplemental disclosure of noncash investing and financing activities
Noncash common stock issuances	$	21	$	21	$	22
Common stock dividends declared but not yet paid		224		217		208

(1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow.

(2) In January, April, July, and October of 2015, 2014, and 2013, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

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Schedule II - Consolidated Valuation And Qualifying Accounts (Tables)

12 Months Ended

Dec. 31, 2015

Schedule II - Consolidated Valuation And Qualifying Accounts [Abstract]

Schedule II - Consolidated Valuation And Qualifying Accounts

PG&E Corporation

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2015, 2014, and 2013

(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:
2015:
Allowance for uncollectible accounts (1)	$	66	$	43	$	-	$	55	$	54
2014:
Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66
2013:
Allowance for uncollectible accounts (1)	$	87	$	53	$	-	$	60	$	80

(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, 2015, 2014, and 2013

(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:
2015:
Allowance for uncollectible accounts (1)	$	66	$	43	$	-	$	55	$	54
2014:
Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66
2013:
Allowance for uncollectible accounts (1)	$	87	$	53	$	-	$	60	$	80

(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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Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Disallowed capital expenditures	$ 407	$ 116	$ 196
Pacific Gas And Electric Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
AFUDC interest recorded	48	45	47
AFUDC equity recorded	107	100	101
Nuclear decommissioning obligation accrued	2,500	2,500
Estimated cost recovery on spent nuclear fuel storage proceeding every year	3,500	3,500
Approximate estimated nuclear decommissioning cost in future dollars	6,100	6,100
Disallowed capital expenditures	$ 407	$ 116	$ 196
Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Composite depreciation rate	3.80%	3.77%	3.51%

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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		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Accumulated depreciation		$ (20,617)	$ (19,120)
Net property, plant, and equipment		46,723	43,940
Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment		67,340	63,060
Electricity generating facilities [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	[1]	$ 9,860	9,374
Electricity generating facilities [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		5 years
Electricity generating facilities [Member] | Utility [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		100 years
Electricity distribution facilities [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment		$ 28,476	26,633
Electricity distribution facilities [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		15 years
Electricity distribution facilities [Member] | Utility [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		55 years
Electricity transmission [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment		$ 10,196	9,155
Electricity transmission [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		15 years
Electricity transmission [Member] | Utility [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		75 years
Natural gas distribution facilities [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment		$ 10,397	9,741
Natural gas distribution facilities [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		5 years
Natural gas distribution facilities [Member] | Utility [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		60 years
Natural gas transportation and storage [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment		$ 6,352	5,937
Natural gas transportation and storage [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		5 years
Natural gas transportation and storage [Member] | Utility [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		65 years
Construction Work In Progress [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment		$ 2,059	$ 2,220

[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 13 below.)

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Summary Of Significant Accounting Policies (Schedule Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Balance at beginning of year	$ 3,575	$ 3,538
Revision in estimated cash flows	13	(16)
Accretion	169	163
Liabilities settled	(114)	(110)
Balance at end of year	$ 3,643	$ 3,575

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New and Significant Accounting Policies (Reclassifications Out of Accumulated Other Comprehensived Income) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance		$ 11	$ 50
Change in investments		(17)	(25)	$ 38
Total other comprehensive income (loss)		(18)	(39)	151
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance		(7)	11	50
Net actuarial loss tax		0	10	80
Change in investments tax		12	17	26
Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account	[1]	(26)	(28)
Amortization of prior service cost	[1]	19	26
Amortization of net actuarial loss	[1]	9	2
Realized gain on investments		(17)	(30)
Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss		(107)	(616)
Unrecognized prior service cost			1
Transfer to regulatory account		104	601
Change in investments			5
Other Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance		15	15
Unrecognized net actuarial loss		4
Unrecognized prior service cost		15
Amortization of prior service cost		19	23	23
Amortization of net actuarial loss		4	2	6
Total other comprehensive income (loss)		1	0
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance		16	15	15
Other Benefits [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account	[1]	(13)	(15)
Amortization of prior service cost	[1]	11	14
Amortization of net actuarial loss	[1]	3	1
Realized gain on investments		0	0
Net actuarial loss tax		1	1
Transfer To Regulatory Account Tax		9	10
Amortization of prior service cost tax		8	9
Realized gain on investments tax		0	0
Other Benefits [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss		(31)	(28)
Unrecognized prior service cost			0
Transfer to regulatory account		31	28
Change in investments			0
Net actuarial loss tax		21	19
Transfer To Regulatory Account Tax		21	19
Change in investments tax			0
Amortization of prior service cost tax			0
Other Investments [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance		17	42
Total other comprehensive income (loss)		(17)	(25)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance		0	17	42
Other Investments [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account	[1]	0	0
Amortization of prior service cost	[1]	0	0
Amortization of net actuarial loss	[1]	0	0
Realized gain on investments		(17)	(30)
Net actuarial loss tax		0	0
Transfer To Regulatory Account Tax		0	0
Amortization of prior service cost tax		0	0
Realized gain on investments tax		12	20
Other Investments [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss		0	0
Unrecognized prior service cost			0
Transfer to regulatory account		0	0
Change in investments			5
Net actuarial loss tax		0	0
Transfer To Regulatory Account Tax		0	0
Change in investments tax			4
Amortization of prior service cost tax			0
Pension [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance		(21)	(7)
Total other comprehensive income (loss)		(2)	(14)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance		(23)	(21)	$ (7)
Realized gain on investments tax		0
Pension [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account	[1]	(13)	(13)
Amortization of prior service cost	[1]	8	12
Amortization of net actuarial loss	[1]	6	1
Realized gain on investments		0	0
Net actuarial loss tax		4	1
Transfer To Regulatory Account Tax		10	9
Amortization of prior service cost tax		7	8
Realized gain on investments tax			0
Pension [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss		(76)	(588)
Unrecognized prior service cost			1
Transfer to regulatory account		73	573
Change in investments			0
Net actuarial loss tax		51	404
Transfer To Regulatory Account Tax		$ 51	394
Change in investments tax			0
Amortization of prior service cost tax			$ 0

[1] These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.)

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Regulatory Assets, Liabilities, And Balancing Accounts (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Deferred income taxes regulatory asset recovery maximum (years)	47 years
Utility retained generation asset costs	$ 1,200
Weighted average remaining life of Utility retained generation assets (years)	10 years
Environmental compliance costs regulatory asset recovery (years)	32 years
Price risk management regulatory assets recovery (years)	10 years
Recovery of costs related to debt reacquired or redeemed prior to maturity (years)	11 years
Current regulatory liabilities	$ 676	$ 261
Current regulatory assets	517	$ 444
Bill Credit to Natural Gas Customers	$ 400

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Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Total long-term regulatory assets		$ 7,029	$ 6,322
Deferred income taxes regulatory asset recovery maximum (years)		47 years
Weighted average remaining life of Utility retained generation assets (years)		10 years
Environmental compliance costs regulatory asset recovery (years)		32 years
Price risk management regulatory assets recovery (years)		10 years
Recovery of costs related to debt reacquired or redeemed prior to maturity (years)		11 years
Retained Generation Asset Costs		$ 1,200
Pension benefits regulatory assets recovery (years)		Indefinitely
Other regulatory assets recovery (years)		Various
Current regulatory assets		$ 517	444
Pension Plans Defined Benefit [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[1]	2,414	2,347
Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[1]	3,054	2,390
Utility Retained Generation [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[2]	411	456
Environmental Compliance Costs [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[1]	748	717
Price Risk Management [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[1]	138	127
Electromechanical meters [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[3]	0	70
Current regulatory assets		70
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[1]	94	113
Other Regulatory Assets ( Liabilities) [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets		$ 170	$ 102

[1] Represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. Pension benefits also includes amounts that otherwise would be recorded to accumulated other comprehensive income/loss in the Consolidated Balance Sheets. (See Note 11 below.)

[2] 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, 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.

[3] Represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter devices. As of December 31, 2015, the remaining balance of $70 million is included in current regulatory assets on the Consolidated Balance Sheets.

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Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities		$ 6,321	$ 6,290
Cost Of Removal Obligation [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	[1]	4,605	4,211
Recoveries In Excess Of ARO [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	[2]	631	754
Public Purpose Programs [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	[3]	600	701
Other Regulatory Assets ( Liabilities) [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities		$ 485	$ 624

[1] Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.

[2] 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 10 below.)

[3] 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.

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Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	$ 1,760	$ 2,266
Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	715	1,090
Electric Distribution [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	380	344
Utility Generation [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	122	261
Public Purpose Programs [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	155	109
Public Purpose Programs [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	244	154
Gas Distribution [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	493	566
Energy Procurement [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	262	608
Energy Procurement [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	112	188
Other [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	348	378
Other [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	$ 359	$ 748

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Debt (Narrative) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt [Line Items]
Interest including LIBOR on credit facilities		Borrowings under each amended and restated credit agreement (other than swing line loans) will bear interest based, at each borrower’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 overnight federal funds rate, and the one-month LIBOR plus an applicable margin. The applicable margin for LIBOR loans will range between 0.9% and 1.475% under PG&E Corporation’s amended and restated credit agreement and between 0.8% and 1.275% under the Utility’s amended and restated credit agreement. The applicable margin for base rate loans will range between 0% and 0.475% under PG&E Corporation’s amended and restated credit agreement and between 0% and 0.275% under the Utility’s amended and restated credit agreement. In addition, the facility fee under PG&E Corporation’s and the Utility’s amended and restated credit agreements will range between 0.1% and 0.275% and between 0.075% and 0.225%, respectively.
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, maturities (days)		365 days
Short-term debt matured		$ (300)	$ 0	$ 0
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	[1]	$ 3,000
Commercial paper average yield		0.42%
Line of Credit Facility, Expiration Date		Apr. 27, 2020
Short-term debt matured		$ (300)	$ 0	$ 0
PG&E Corporation [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	[2]	$ 300
Commercial paper average yield		0.38%
Line of Credit Facility, Expiration Date		Apr. 27, 2020
Credit Facilities [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity		$ 3,300
Commercial Paper [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average outstanding borrowings		678
Maximum outstanding balance		1,500
Commercial Paper [Member] | PG&E Corporation [Member]
Debt [Line Items]
Average outstanding borrowings		64
Maximum outstanding balance		$ 128

[1] Includes a $500 million sublimit for letters of credit and a $75 million commitment for swingline loans.

[2] Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

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Debt (Schedule Of Long-Term Debt) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Debt [Line Items]
Total long-term debt, net of current portion		$ 16,030	$ 15,050
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Total long-term debt, net of current portion		15,680	14,700
Utility [Member]
Debt [Line Items]
Unamortized discount, net of premium		(53)	(43)
Total senior notes, net of current portion		14,572	13,432
Less: current portion		160
Total pollution control bonds		1,108	1,268
PG&E Corporation [Member]
Debt [Line Items]
Total long-term debt, net of current portion		350	350
Senior Notes, 2.40% Due 2019 [Member] | PG&E Corporation [Member]
Debt [Line Items]
Senior notes		350	350
Senior Notes, 3.40% Due 2024 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		350	350
Senior Notes, 5.625% Due 2017 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		700	700
Senior Notes, 8.25% Due 2018 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		800	800
Senior Notes, 3.50% Due 2020 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		800	800
Senior Notes, 4.25% Due 2021[Member] | Utility [Member]
Debt [Line Items]
Senior notes		300	300
Senior Notes, 3.25% Due 2021 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		250	250
Senior Notes, 2.45% Due 2022 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		400	400
Senior Notes, 3.25% Due 2023 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		375	375
Senior Notes, 3.85% Due 2023 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		300	300
Senior Notes, 3.75% Due 2024 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		450	450
Senior Notes, 3.50%, Due 2025 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		600	0
Senior Notes, 6.05% Due 2034 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		3,000	3,000
Senior Notes, 5.80% Due 2037 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		950	950
Senior Notes, 6.35% Due 2038 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		400	400
Senior Notes, 6.25% Due 2039 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		550	550
Senior Notes, 5.40% Due 2040 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		800	800
Senior Notes, 4.50% Due 2041 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		250	250
Senior Notes, 4.45% Due 2042 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		400	400
Senior Notes, 3.75% Due 2042 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		350	350
Senior Notes, 4.60% Due 2043 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		375	375
Senior Notes, 5.125% Due 2043 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		500	500
Senior Notes, 4.75% Due 2044 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		675	675
Senior Notes, 4.30% Due 2045 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		600	500
Senior Notes, 4.25%, Due 2046 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		450	0
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 [Member] | Utility [Member]
Debt [Line Items]
Pollution control bonds	[1],[2]	614	614
Pollution Control Bonds, Series 2004 A-D, 4.75%, Due 2023 [Member] | Utility [Member]
Debt [Line Items]
Pollution control bonds	[3]	345	345
Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member] | Utility [Member]
Debt [Line Items]
Pollution control bonds	[1],[4]	$ 309	$ 309
Interest rate on bonds, minimum		0.01%
Interest rate on bonds, maximum		0.01%

[1] At December 31, 2015, interest rates on these bonds were 0.01%.

[2] Each series of these bonds is supported by a separate letter of credit. In December 2015, the letters of credit were extended to December 1, 2020. 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] Each series of these bonds is supported by a separate direct-pay letter of credit. Series C and D letters of credit expire on December 3, 2016 to coincide with the maturity of the underlying bonds. Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.

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Debt (Schedule Of Long-Term Debt Repayments) (Details) $ in Millions	Dec. 31, 2015 USD ($)
Debt [Line Items]
Total consolidated long-term debt	$ 16,243
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	5.05%
Fixed rate obligations	$ 14,970
Variable interest rate as of December 31, 2015	0.01%
Variable rate obligations	$ 923	[1]
PG&E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	2.40%
Fixed rate obligations	$ 350
2016 [Member]
Debt [Line Items]
Total consolidated long-term debt	$ 160
2016 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Variable interest rate as of December 31, 2015	0.01%
Variable rate obligations	$ 160	[1]
2016 [Member] | PG&E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
2017 [Member]
Debt [Line Items]
Total consolidated long-term debt	$ 700
2017 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	5.63%
Fixed rate obligations	$ 700
Variable interest rate as of December 31, 2015	0.00%
Variable rate obligations	$ 0	[1]
2017 [Member] | PG&E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
2018 [Member]
Debt [Line Items]
Total consolidated long-term debt	$ 800
2018 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	8.25%
Fixed rate obligations	$ 800
Variable interest rate as of December 31, 2015	0.00%
Variable rate obligations	$ 0	[1]
2018 [Member] | PG&E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
2019 [Member]
Debt [Line Items]
Total consolidated long-term debt	$ 499
2019 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Variable interest rate as of December 31, 2015	0.01%
Variable rate obligations	$ 149	[1]
2019 [Member] | PG&E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	2.40%
Fixed rate obligations	$ 350
2020 [Member]
Debt [Line Items]
Total consolidated long-term debt	$ 1,414
2020 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	3.50%
Fixed rate obligations	$ 800
Variable interest rate as of December 31, 2015	0.01%
Variable rate obligations	$ 614	[1]
2020 [Member] | PG&E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Thereafter [Member]
Debt [Line Items]
Total consolidated long-term debt	$ 12,670
Thereafter [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	4.91%
Fixed rate obligations	$ 12,670
Variable interest rate as of December 31, 2015	0.00%
Variable rate obligations	$ 0	[1]
Thereafter [Member] | PG&E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0

[1] These bonds, due in 2016 and 2026, are backed by separate letters of credit that expire on December 3, 2016, June 5, 2019, or December 1, 2020.

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Debt (Schedule Of Line Of Credit) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Jul. 02, 2015	Apr. 27, 2015
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Expiration date for credit agreement		Apr. 27, 2020
Facility Limit	[1]	$ 3,000
Letters of Credit outstanding		33
Commercial Paper		1,019
Facility Availability		1,948
Letters of credit, sublimit		500		$ 1,000
Swingline loans, sublimit		75		300
Commercial Paper Sublimit		$ 2,500	$ 1,750
PG&E Corporation [Member]
Debt [Line Items]
Expiration date for credit agreement		Apr. 27, 2020
Facility Limit	[2]	$ 300
Letters of Credit outstanding		0
Commercial Paper		0
Facility Availability		300
Letters of credit, sublimit		50		$ 100
Swingline loans, sublimit		100
Commercial Paper Sublimit		300
Credit Facilities [Member]
Debt [Line Items]
Facility Limit		3,300
Letters of Credit outstanding		33
Commercial Paper		1,019
Facility Availability		$ 2,248

[1] Includes a $500 million sublimit for letters of credit and a $75 million commitment for swingline loans.

[2] Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

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Common Stock And Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Common stock, shares outstanding	492,025,443	475,913,404
Dividend per share	$ 0.455
Debt covenant ratio of total consolidated debt to total consolidated capitalization percentage	65.00%
Percentage of equity for capital structure to be maintained	52.00%
Common stock	$ 11,282.0	$ 10,421.0
Equity Contract [Member]
Equity distribution agreement amount	$ 500.0
Common stock shares issued	1,400,000
Fees and Commissions	$ 1.0
Common stock	$ 74.0
Underwritten Public Offering [Member]
Sale of common stock in an underwritten public offering	6,800,000
Common stock issued, amount	$ 352.0
Four Zero One K Plan D R S P P Shared Based Compensation Plans [Member]
Common stock shares issued	7,900,000
Common stock	$ 354.0
Utility [Member]
Net restricted assets for revolving credit facility ratio requirement	1,520.0
Net restricted assets for equity component requirement	15,200.0
Additional Common Stock Dividends	$ 110.0

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Common Stock And Share-Based Compensation (Long-Term Incentive Plan) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issued for LTIP, maximum	17,000,000
Shares available for LTIP award	15,674,803
Total Compensation Expense (pre-tax)	$ 93	$ 78	$ 64
Total Compensation Expense (after-tax)	55	47	38
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total Compensation Expense (pre-tax)	47	42	36
Performance Shares, Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total Compensation Expense (pre-tax)	$ 46	$ 36	$ 28

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Common Stock And Share-Based Compensation (Restricted Stock Units) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Common Stock And Share-Based Compensation [Abstract]
Total fair value	$ 57	$ 34	$ 30
Total unrecognized compensation costs	$ 45
Remaining weighted average period, Years	1 year 5 months 23 days
Nonvested at January 1, Number of Restricted Stock Units	2,538,357
Granted, Number of Restricted Stock Units	820,834
Vested, Number of Restricted Stock Units	(1,304,150)
Forfeited, Number of Restricted Stock Units	(82,142)
Nonvested at December 31, Number of Restricted Stock Units	1,972,899	2,538,357
Nonvested at January 1, Weighted Average Grant-Date Fair Value	$ 43.39
Granted, Weighted Average Grant Date Fair Value	53.30	$ 43.76	$ 42.92
Vested, Weighted Average Grant Date Fair Value	43.51
Forfeited, Weighted Average Grant Date Fair Value	45.63
Nonvested at December 31, Weighted Average Grant-Date Fair Value	$ 47.33	$ 43.39

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Common Stock And Share-Based Compensation (Performance Shares) (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted-average period (years)		1 year 5 months 12 days
Performance Shares, Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized		$ 36
Nonvested at January 1, Number of Performance Shares		1,693,939
Granted, Number of Performance Shares		669,519
Vested, Number of Performance Shares		(421,262)
Forfeited, Number of Performance Shares	[1]	(491,584)
Nonvested at December 31, Number of Performance Shares		1,450,612	1,693,939
Nonvested at January 1, Weighted Average Exercise Price		$ 42.37
Granted, Weighted Average Exercise Price		68.27	$ 51.81	$ 33.45
Vested, Weighted Average Exercise Price		33.57
Forfeited, Weighted Average Exercise Price	[1]	35.56
Nonvested at December 31, Weighted Average Exercise Price		$ 59.24	$ 42.37

[1] Includes performance shares that expired with 50% value as a result of total shareholder return results.

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Preferred Stock (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pacific Gas And Electric Company [Member]
Preferred Stock [Line Items]
Preferred stock dividends	$ 14	$ 14	$ 14
$25 Par Value [Member]
Preferred Stock [Line Items]
Preferred stock, par value	$ 25
Preferred stock, shares issued	75,000,000
$25 Par Value [Member] | Pacific Gas And Electric Company [Member]
Preferred Stock [Line Items]
Preferred stock, par value	$ 25
$100 Par Value [Member] | Pacific Gas And Electric Company [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
Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member]
Preferred Stock [Line Items]
Preferred stock dividends per share, low range	$ 1.25
Preferred stock dividends per share, high range	1.5
Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member]
Preferred Stock [Line Items]
Preferred stock dividends per share, low range	1.09
Preferred stock dividends per share, high range	$ 1.25

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Preferred Stock (Summary Of Issued And Outstanding Preferred Stock) (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) $ / shares
Minimum [Member]
Preferred Stock [Line Items]
Redemption Price | $ / shares	$ 25.75
Maximum [Member]
Preferred Stock [Line Items]
Redemption Price | $ / shares	$ 27.25
Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member]
Preferred Stock [Line Items]
Nonredeemable preferred stock, value | $	$ 145
Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Minimum [Member]
Preferred Stock [Line Items]
Preferred stock interest rate	5.00%
Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member]
Preferred Stock [Line Items]
Redeemable preferred stock, value | $	$ 113
Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Minimum [Member]
Preferred Stock [Line Items]
Preferred stock interest rate	4.36%
6.00% Series [Member] | Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Maximum [Member]
Preferred Stock [Line Items]
Preferred stock interest rate	6.00%
5.00% Series A [Member] | Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Maximum [Member]
Preferred Stock [Line Items]
Preferred stock interest rate	5.00%

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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 ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Income available for common shareholders	$ 874	$ 1,436	$ 814
Weighted average common shares outstanding, basic	484	468	444
Add Incremental Shares From Assumed conversions:
Employee share-based compensation	3	2	1
Weighted average common shares outstanding, diluted	487	470	445
Total earnings per common share, diluted	$ 1.79	$ 3.06	$ 1.83

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Income Taxes (Schedule Of Income Tax Provision) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current, Federal	$ (89)	$ (84)	$ (218)
Current, State	11	(41)	(26)
Deferred, Federal	131	396	552
Deferred, State	(76)	78	(35)
Tax credits	(4)	(4)	(5)
Income Tax Provision	(27)	345	268
Pacific Gas And Electric Company [Member]
Current, Federal	(88)	(84)	(222)
Current, State	6	(29)	(23)
Deferred, Federal	136	426	604
Deferred, State	(69)	75	(28)
Tax credits	(4)	(4)	(5)
Income Tax Provision	(19)	384	326
PG&E Corporation [Member]
Income Tax Provision	$ 3	$ 39	$ 48

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Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Pacific Gas And Electric Company [Member]
Customer advances for construction		$ 69	$ 88
Environmental reserve		85	111
Compensation		145	173
Tax carryforwards		1,462	946
Greenhouse Gas Allowances		340	56
Other		61	100
Total deferred income tax assets		2,162	1,474
Regulatory balancing accounts		691	512
Property related basis differences		9,638	8,666
Income tax regulatory asset	[1]	1,245	974
Other		75	86
Total deferred income tax liabilities		11,649	10,238
Total net deferred income tax liabilities		9,487	8,764
Included in current liabilities (assets)		0	(9)
Included in noncurrent liabilities		9,487	8,773
PG&E Corporation [Member]
Customer advances for construction		69	88
Environmental reserve		85	111
Compensation		219	244
Tax carryforwards		1,703	1,177
Greenhouse Gas Allowances		340	56
Other		44	74
Total deferred income tax assets		2,460	1,750
Regulatory balancing accounts		691	512
Property related basis differences		9,656	8,683
Income tax regulatory asset	[1]	1,244	974
Other		75	88
Total deferred income tax liabilities		11,666	10,257
Total net deferred income tax liabilities		9,206	8,507
Included in current liabilities (assets)		0	(6)
Included in noncurrent liabilities		$ 9,206	$ 8,513

[1] Represents the deferred income tax component of the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. (See Note 3 above.)

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Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pacific Gas And Electric Company [Member]
Federal statutory income tax rate		35.00%	35.00%	35.00%
State income tax (net of federal benefit)	[1]	(4.80%)	1.60%	(2.20%)
Effect of regulatory treatment of fixed asset differences	[2]	(33.70%)	(14.70%)	(3.80%)
Tax credits		(1.30%)	(0.70%)	(0.40%)
Benefit of loss carryback		(1.50%)	(0.80%)	(1.00%)
Non deductible penalties	[3]	4.30%	0.30%	0.70%
Other, net		(0.20%)	0.40%	(0.90%)
Effective tax rate		(2.20%)	21.10%	27.40%
PG&E Corporation [Member]
Federal statutory income tax rate		35.00%	35.00%	35.00%
State income tax (net of federal benefit)	[1]	(4.90%)	1.40%	(3.10%)
Effect of regulatory treatment of fixed asset differences	[2]	(33.60%)	(15.00%)	(4.20%)
Tax credits		(1.30%)	(0.70%)	(0.40%)
Benefit of loss carryback		(1.50%)	(0.80%)	(1.10%)
Non deductible penalties	[3]	4.30%	0.30%	0.80%
Other, net		(1.10%)	(0.80%)	(2.20%)
Effective tax rate		(3.10%)	19.40%	24.80%

[1] Includes the effect of state flow-through ratemaking treatment.

[2] Represents effect of federal flow-through ratemaking treatment including those deductions related to repairs and certain other property-related costs discussed below in the 2014 GRC Impact section.

[3] Represents the effects of non-tax deductible fines and penalties associated with the Penalty Decision. For more information about the Penalty Decision see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

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Income Taxes (Schedule Of Change In Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pacific Gas And Electric Company [Member]
Balance at beginning of year	$ 707	$ 660	$ 575
Additions for tax position taken during a prior year	40	7	12
Reductions for tax position taken during a prior year	(349)	(9)	(6)
Additions for tax position taken during the current year	64	61	79
Settlements	0	(12)	0
Balance at end of year	462	707	660
PG&E Corporation [Member]
Balance at beginning of year	713	666	581
Additions for tax position taken during a prior year	40	7	12
Reductions for tax position taken during a prior year	(349)	(9)	(6)
Additions for tax position taken during the current year	64	61	79
Settlements	0	(12)	0
Balance at end of year	$ 468	$ 713	$ 666

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Income Taxes (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year	$ 50
Decrease of unrecognized tax benefit	60
State [Member]
Net operating loss carryforwards	80
Tax credit carryforward, amount	59
Loss carryforwards, charitable contribution	$ 119
Charitable Contribution Carryforward Expiration Date [Minimum]	Dec. 31, 2019
Charitable Contribution Carryforward Expiration Date [Maximum]	Dec. 31, 2020
Federal [Member]
Net operating loss carryforwards	$ 4,856
Capital loss carryforwards	29
Tax credit carryforward, amount	110
Loss carryforwards, charitable contribution	$ 178
Tax Credit Carryforward Expiration Date [Minimum]	Dec. 31, 2029
Tax Credit Carryforward Expiration Date [Maximum]	Dec. 31, 2035
Charitable Contribution Carryforward Expiration Date [Minimum]	Dec. 31, 2017
Charitable Contribution Carryforward Expiration Date [Maximum]	Dec. 31, 2020
Minimum [Member] | State [Member]
Tax credit carryforward expiration date	Dec. 31, 2033
Minimum [Member] | Federal [Member]
Tax credit carryforward expiration date	Dec. 31, 2029
Maximum [Member] | State [Member]
Tax credit carryforward expiration date	Dec. 31, 2034
Maximum [Member] | Federal [Member]
Tax credit carryforward expiration date	Dec. 31, 2035

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Derivatives And Hedging Activities (Volumes Of Outstanding Derivative Contracts) (Details)		Dec. 31, 2015 MMBTU MWh	Dec. 31, 2014 MMBTU MWh
Forwards And Swaps [Member] | Natural Gas (MMBtus)[Member]
Derivative [Line Items]
Derivative Number of Instruments Held | MMBTU	[1],[2]	333,091,813	308,130,101
Forwards And Swaps [Member] | Electricity (Megawatt-hours) [Member]
Derivative [Line Items]
Derivative Number of Instruments Held | MWh		3,663,512	5,346,787
Options [Member] | Natural Gas (MMBtus)[Member]
Derivative [Line Items]
Derivative Number of Instruments Held | MMBTU	[1],[2]	111,550,004	164,418,002
Congestion Revenue Rights [Member] | Electricity (Megawatt-hours) [Member]
Derivative [Line Items]
Derivative Number of Instruments Held | MWh	[3]	216,383,389	224,124,341

[1] Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.

[2] Million British Thermal Units.

[3] CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

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Derivatives And Hedging Activities (Outstanding Derivative Balances) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Other Current Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	$ 97	$ 73
Cash Collateral	25	19
Total Derivative Balances	118	88
Derivative Liability Offsetting Derivative Asset	(4)	(4)
Other Noncurrent Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	172	178
Cash Collateral	0	0
Total Derivative Balances	170	165
Derivative Liability Offsetting Derivative Asset	(2)	(13)
Other Current Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance		(78)
Gross Derivative Balance	(102)
Cash Collateral	44	26
Total Derivative Balances	(54)	(48)
Derivative Asset Offsetting Derivative Liability	4	4
Other Noncurrent Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(140)	(140)
Cash Collateral	21	9
Total Derivative Balances	(117)	(118)
Derivative Asset Offsetting Derivative Liability	2	13
Gross Derivative Balance [Member]
Derivatives And Hedging Activities [Line Items]
Total Gross Derivative Balance	27	33
Netting [Member]
Derivatives And Hedging Activities [Line Items]
Derivative Asset Offsetting Derivative Liability	0	0
Cash Collatera [lMember]
Derivatives And Hedging Activities [Line Items]
Cash Collateral	90	54
Total Derivatve Balance [Member]
Derivatives And Hedging Activities [Line Items]
Total Derivative Balances	$ 117	$ 87

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Derivatives And Hedging Activities (Gains And Losses On Derivative Instruments) (Details) - PGE Corporation Utility [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Unrealized (loss) gain - regulatory assets and liabilities	[1]	$ (6)	$ 124	$ 238
Realized loss-cost of electricity	[2]	(14)	(83)	(178)
Realized loss-cost of natural gas	[2]	(10)	(8)	(22)
Total commodity risk instruments		$ (30)	$ 33	$ 38

[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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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		Dec. 31, 2015	Dec. 31, 2014
Derivatives And Hedging Activities [Abstract]
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized		$ (2)	$ (47)
Related derivatives in an asset position		0	0
Collateral posting in the normal course of business related to these derivatives		0	44
Net position of derivative contracts/additional collateral posting requirements	[1]	$ (2)	$ (3)

[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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Fair Value Measurements (Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value		$ 314	$ 324
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		64	94
Total assets		2,321	2,478
Other investments			33
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		829	687
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		259	232
Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[1]	19	2
Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		64	94
Total assets		3,428	3,399
Other investments			33
Nuclear Decommissioning Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[2]	2,784
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		36	17
Global equity securities		1,520	1,585
Fixed-income securities		694	741
Total assets	[2]	2,250	2,343
Nuclear Decommissioning Trusts [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Global equity securities		13	13
Fixed-income securities		521	389
Total assets	[2]	534	402
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		36	17
Global equity securities		1,533	1,598
Fixed-income securities		1,215	1,130
Total assets	[2]		2,745
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
Gas			1
Electric		69	47
Total liabilities		69	47
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		10	18
Electric		9	17
Gas		1	1
Electric		1	5
Gas		2	3
Total liabilities		3	8
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		259	232
Electric		259	232
Electric		170	163
Total liabilities		170	163
Price Risk Management Instruments [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[1]	19	2
Electric	[1]	18	2
Gas	[1]	1
Electric	[1]	(70)	(52)
Gas	[1]	(1)
Total liabilities	[1]	(71)	(52)
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		288	253
Electric		286	251
Gas		2	2
Electric		170	163
Gas		1	3
Total liabilities		171	166
Rabbi Trusts [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fixed-income securities		57	42
Life insurance contracts		70	72
Total assets		127	114
Rabbi Trusts [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fixed-income securities		57	42
Life insurance contracts		70	72
Total assets		127	114
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		7	7
Total assets		7	7
Long-Term Disability Trust [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Global equity securities		26	25
Fixed-income securities		132	128
Total assets		158	153
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		7	7
Global equity securities		26	25
Fixed-income securities		132	128
Total assets		$ 165	$ 160

[1] Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

[2] Represents amounts before deducting $314 million and $324 million at December 31, 2015 and 2014, respectively, primarily related to deferred taxes on appreciation of investment value.

XML

Fair Value Measurements (Level 3 Measurements And Sensitivity Analysis) (Detail) $ in Millions		12 Months Ended
		Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value		$ 259	$ 232
Liabilities, Fair Value		$ 63	$ 63
Fair value measurement Valuation technique		Market approach	Market approach
Fair value measurement Unobservable Input		CRR auction prices	CRR auction prices
Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value		$ 0	$ 0
Liabilities, Fair Value		$ 107	$ 100
Fair value measurement Valuation technique		Discounted cash flow	Discounted cash flow
Fair value measurement Unobservable Input		Forward prices	Forward prices
Minimum [Member] | CRR Auction Prices [Member] | Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	(161.36)	(15.97)
Minimum [Member] | Forward Prices [Member] | Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	15.08	16.04
Maximum [Member] | CRR Auction Prices [Member] | Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	8.76	8.17
Maximum [Member] | Forward Prices [Member] | Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	37.27	56.21

[1] Represents price per megawatt-hour

XML

Fair Value Measurements (Level 3 Reconciliation) (Details) - Fair Value, Inputs, Level 3 [Member] - Price Risk Management Instruments [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Liability balance as of January 1		$ 69	$ (30)
Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts	[1]	20	99
Liability balance as of December 31		$ 89	$ 69

[1] The costs related to 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.

XML

Fair Value Measurements (Carrying Amount And Fair Value Of Financial Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Carrying Amount [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	$ 350	$ 350
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	14,918	13,778
Fair Value Inputs Level2 [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	354	352
Fair Value Inputs Level2 [Member] | Pacific Gas And Electric Company [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	$ 16,422	$ 15,851

XML

Fair Value Measurements (Schedule Of Unrealized Gains Losses Related To Available-For-Sale Investments) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014
Schedule of Available-for-sale Securities [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value		$ 314		$ 324
Money Market Investments [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		36		17
Total Unrealized Gains		0		0
Total Unrealized Losses		0		0
Total Fair Value		36		17
Global equity securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		508		520
Total Unrealized Gains		1,034		1,087
Total Unrealized Losses		(9)		(9)
Total Fair Value		1,533		1,598
Fixed-Income Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		1,165		1,059
Total Unrealized Gains		58		75
Total Unrealized Losses		(8)		(4)
Total Fair Value		1,215		1,130
Securities (Assets) [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		1,709	[1],[2]	1,601
Total Unrealized Gains		1,092	[1],[2]	1,190
Total Unrealized Losses		(17)	[1],[2]	(13)
Total Fair Value		$ 2,784	[1],[2]	2,778
Other securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost				5
Total Unrealized Gains				28
Total Unrealized Losses				0
Total Fair Value				33
Nuclear Decommissioning Trusts [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	[1]			1,596
Total Unrealized Gains	[1]			1,162
Total Unrealized Losses	[1]			(13)
Total Fair Value	[1]			$ 2,745

[1] Represents amount before deducting $324 million, primarily related to deferred taxes on appreciation of investment value.

[2] Represents amounts before deducting $314 million and $324 million at December 31, 2015 and 2014, respectively, primarily related to deferred taxes on appreciation of investment value.

XML

Fair Value Measurements (Schedule Of Maturities On Debt Securities) (Details) $ in Millions	Dec. 31, 2015 USD ($)
Fair Value Measurements [Abstract]
Less than 1 year	$ 18
1-5 years	470
5-10 years	273
More than 10 years	454
Total maturities of debt securities	$ 1,215

XML

Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value Measurements [Abstract]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 1,268	$ 1,336	$ 1,619
Gross realized gains on sales of securities held as available-for-sale	55	118	94
Gross realized losses on sales of securities held as available-for-sale	$ (37)	$ (12)	$ (13)

XML

Employee Benefit Plans (Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Noncurrent liability		$ (2,622)		$ (2,561)
Decrease in other comprehensive income		1		14	$ (113)
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1		2,092		1,892
Actual return on plan assets		(26)		241
Company contributions		61		57
Plan participant contribution		68		63
Benefits and expenses paid		(160)		(161)
Fair value of plan assets at December 31		2,035		2,092	1,892
Projected benefit obligation at January 1		1,811		1,597
Service cost for benefits earned		55		45
Interest cost		71		76	74
Actuarial (gain) loss		(98)		166
Benefits and expenses paid		(146)		(140)
Federal subsidy on benefits paid		4		4
Projected benefit obligation at December 31		1,766		1,811	1,597
Current liability	[1]	(75)		(87)
Net assets (liabilities) at end of year		269		281
Noncurrent asset	[1]	344		368
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1		14,216		12,527
Actual return on plan assets		(176)		1,946
Company contributions		334		332
Benefits and expenses paid		(629)		(589)
Fair value of plan assets at December 31		13,745		14,216	12,527
Projected benefit obligation at January 1		16,696		14,077
Service cost for benefits earned		479		383
Interest cost		673		695	627
Actuarial (gain) loss		(922)		2,131
Plan amendments		1		(1)
Transitional costs		1
Benefits and expenses paid		(629)		(589)
Projected benefit obligation at December 31		16,299	[2]	16,696	$ 14,077
Current liability		(6)		(6)
Noncurrent liability		(2,547)		(2,474)
Net assets (liabilities) at end of year		$ (2,553)		$ (2,480)

[1] At December 31, 2015 and 2014, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.

[2] PG&E Corporation's accumulated benefit obligation was $14.7 billion and $14.9 billion at December 31, 2015 and 2014, respectively.

XML

Employee Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		$ 55	$ 45	$ 53
Interest cost		71	76	74
Expected return on plan assets		(112)	(103)	(79)
Amortization of prior service cost		19	23	23
Amortization of net actuarial loss		4	2	6
Net periodic benefit cost		37	43	77
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		479	383	468
Interest cost		673	695	627
Expected return on plan assets		(873)	(807)	(650)
Amortization of prior service cost		15	20	20
Amortization of net actuarial loss		10	2	111
Net periodic benefit cost		304	293	576
Less: transfer to regulatory account	[1]	34	42	(238)
Total		$ 338	$ 335	$ 338

[1] The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.

XML

Employee Benefit Plans (Estimated Amortized Net Periodic Benefit For 2012) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Unrecognized prior service cost	$ 15
Unrecognized net actuarial loss	4
Total	19
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Unrecognized prior service cost	8
Unrecognized net actuarial loss	24
Total	$ 32

XML

Employee Benefit Plans (Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	6.10%
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate range	4.27-4.48	3.89-4.09	4.70-5.00
Expected return on plan assets percentage range	3.20-6.60	3.30-6.70	3.50-6.70
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.37%	4.00%	4.89%
Average rate of future compensation increases	4.00%	4.00%	4.00%
Expected return on plan assets	6.10%	6.20%	6.50%

XML

Employee Benefit Plans (Schedule Of Assumed Health Care Cost Trend) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Employee Benefit Plans [Abstract]
Effect on postretirement benefit obligation, One-Percentage-Point Increase	$ 113
Effect on postretirement benefit obligation, One-Percentage-Point Decrease	(114)
Effect on service and interest cost, One-Percentage-Point Increase	9
Effect on service and interest cost, One-Percentage-Point Decrease	$ (9)
Assumed health care cost trend rate	7.20%
Ultimate trend rate	4.00%
Assumed return	6.10%
10 year actual rate of return	7.80%
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used	688

XML

Employee Benefit Plans (Target Asset Allocation Percentages) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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 Plans Defined Benefit [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	58.00%	58.00%	59.00%
Fixed Income Securities[Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	60.00%	60.00%	60.00%
Real Assets [member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	7.00%	8.00%	8.00%
Real Assets [member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	10.00%	10.00%	10.00%
Absolute Return [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	3.00%	3.00%	3.00%
Absolute Return [Member] | Pension Plans Defined Benefit [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	32.00%	31.00%	30.00%
Global Equity Securities [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	25.00%	25.00%	25.00%

XML

Employee Benefit Plans (Schedule Of Fair Value Of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	$ 15,793	$ 16,284
Total Fair Value Of Trust Other Net Assets	13	131
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	2,040	2,096
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	13,753	14,188
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	343	387
Fair Value, Inputs, Level 1 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	3,572	3,958
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	1,555	1,604
Fair Value, Inputs, Level 2 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	8,128	8,340
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	142	105	$ 93
Fair Value, Inputs, Level 3 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	2,053	1,890	$ 1,723
Short-term investments [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	20	28
Short-term investments [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	616	663
Short-term investments [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	20	28
Short-term investments [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	247	352
Short-term investments [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
Short-term investments [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	369	311
Short-term investments [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
Short-term investments [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans Defined Benefit [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	146	121
Residential Real Estate [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	1,334	1,295
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	69	72
Residential Real Estate [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	581	620
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 Plans Defined Benefit [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	77	49
Residential Real Estate [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	753	675
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	649	673
Global Equity Securities [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	3,146	3,229
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	104	124
Global Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	903	918
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	545	549
Global Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	2,243	2,311
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 Plans Defined Benefit [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	65	55
Absolute Return [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	660	577
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 Plans Defined Benefit [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 Plans Defined Benefit [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	65	55
Absolute Return [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	$ 660	$ 577

XML

Employee Benefit Plans (Schedule Of Level 3 Reconciliation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	$ 16,284
Balance as of December 31	15,793	$ 16,284
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	2,096
Balance as of December 31	2,040	2,096
Other Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	387
Balance as of December 31	343	387
Other Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	1,604
Balance as of December 31	1,555	1,604
Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	105	93
Relating to assets still held at the reporting date	4	6
Relating to assets sold during the period	0	0
Purchases	34	7
Settlements	(1)	(1)
Balance as of December 31	142	105
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	14,188
Balance as of December 31	13,753	14,188
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	3,958
Balance as of December 31	3,572	3,958
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	8,340
Balance as of December 31	8,128	8,340
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	1,890	1,723
Relating to assets still held at the reporting date	65	101
Relating to assets sold during the period	1	4
Purchases	109	79
Settlements	(12)	(17)
Balance as of December 31	2,053	1,890
Real Estate [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	49	38
Relating to assets still held at the reporting date	5	4
Relating to assets sold during the period	0	0
Purchases	23	7
Settlements	0	0
Balance as of December 31	77	49
Real Estate [Member] | Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	675	544
Relating to assets still held at the reporting date	63	54
Relating to assets sold during the period	0	0
Purchases	17	78
Settlements	(2)	(1)
Balance as of December 31	753	675
Absolute Return [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	55	53
Relating to assets still held at the reporting date	(1)	2
Relating to assets sold during the period	0	0
Purchases	11	0
Settlements	0	0
Balance as of December 31	65	55
Absolute Return [Member] | Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	577	554
Relating to assets still held at the reporting date	(7)	23
Relating to assets sold during the period	0	0
Purchases	90	0
Settlements	0	0
Balance as of December 31	660	577
Corporate Fixed Income Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	1,219
Balance as of December 31	1,160	1,219
Corporate Fixed Income Securities [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	163
Balance as of December 31	150	163
Corporate Fixed Income Securities [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	1,055
Balance as of December 31	1,010	1,055
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	2
Relating to assets still held at the reporting date	0	0
Relating to assets sold during the period	0	0
Purchases	0	0
Settlements	(1)	(1)
Balance as of December 31	0	1
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	8,424
Balance as of December 31	7,997	8,424
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	2,068
Balance as of December 31	1,841	2,068
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	5,718
Balance as of December 31	5,516	5,718
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	638	625
Relating to assets still held at the reporting date	9	24
Relating to assets sold during the period	1	4
Purchases	2	1
Settlements	(10)	(16)
Balance as of December 31	$ 640	$ 638

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Employee Benefit Plans (Schedule Of Estimated Benefits Expected To Be Paid) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
2016	$ 695
2017	739
2018	780
2019	818
2020	854
Thereafter in the succeeding five years	4,728
Employer contribution	334	$ 332
Expected employer contribution next year	327
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2016	89
2017	95
2018	101
2019	107
2020	113
Thereafter in the succeeding five years	593
Employer contribution	61	$ 57
Expected employer contribution next year	61
Federal Subsidy [Member]
Defined Benefit Plan Disclosure [Line Items]
2016	(6)
2017	(7)
2018	(7)
2019	(8)
2020	(8)
Thereafter in the succeeding five years	$ (17)

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Employee Benefit Plans (Schedule Of Employer Contribution Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee Benefit Plans [Abstract]
Retirement Savings Plan expense	$ 89	$ 80	$ 71

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Resolution Of Remaining Chapter 11 Disputed Claims (Changes In The Remaining Net Disputed Claims Liability) (Details) - CAISO And PX [Member] - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Net disputed claims and customer refunds	$ 454	$ 434
Carrying amounts due from CAISO and PX as of the balance sheet date for disputed claims related to the Chapter 11 Filing	228	$ 291
Settlement Refund	$ 312

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Related Party Agreements And Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Current receivables	$ 22	$ 17
Current payables	21	20
Administrative Services Provided To PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility revenues from	6	5	$ 7
Administrative Services Received From PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility expenses from	53	54	45
Utility Employee Benefit Due To PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility expenses from	$ 82	$ 70	$ 57

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Commitments And Contingencies (Legal And Regulatory Contingencies) (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2015 USD ($)		Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Loss Contingencies [Line Items]
Accrued legal liabilities		$ 63,000		$ 55,000
Amount of capital included in property plant and equipment		664,000
Customer bill credit		400,000
CPUC Imposed Penalty Per Day Per Violation		50
Payment To State General Fund		100,000	[1]	200,000
Total Penalty Decision Fines And Remedies		907,000
Disallowed capital expenditures		407,000		116,000	$ 196,000
Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Disallowed capital expenditures		$ 407,000		$ 116,000	$ 196,000
Butte Fire [Member]
Loss Contingencies [Line Items]
Number Of Deaths		2
Number Of Houses Destroyed		571
Number Of Structures Destroyed		965
Loss Contingency Range Of Possible Loss Maximum		$ 350,000
Loss Contingency Range Of Possible Loss Minimum		$ 450,000
Criminal Investigation [Member]
Loss Contingencies [Line Items]
Dismissed pipeline safety acts counts		15
Maximum [Member]
Loss Contingencies [Line Items]
Energy Efficiency Award For Two Thousand And Six Through Two Thousand And Eight Program Cycle		$ 180,000
Maximum [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
S E D fines for self reported violations		16,800
Minimum [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
S E D fines for self reported violations		50
Penalty Decision Future Charges and Costs [Member]
Loss Contingencies [Line Items]
Disallowed Revenue For Pipeline Safety Expenses	[2]	161,000
Total Penalty Decision Fines And Remedies		443,000
Disallowed capital expenditures	[3]	282,000
Penalty Decision Cumulative Charges [Member]
Loss Contingencies [Line Items]
Customer bill credit		400,000
Payment To State General Fund	[1]	300,000
Total Penalty Decision Fines And Remedies		1,107,000
Disallowed capital expenditures	[3]	407,000
Total Penalty Decision [Member]
Loss Contingencies [Line Items]
Customer bill credit		400,000
C P U C Remedial Measures	[4]	50,000
Disallowed Revenue For Pipeline Safety Expenses	[2]	161,000
Payment To State General Fund	[1]	300,000
Total Penalty Decision Fines And Remedies		1,600,000
Disallowed capital expenditures	[3]	689,000
Carmel Incident [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
CPUC Imposed Penalty		$ 10,850
Original Indictment [Member] | Criminal Investigation [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Number of Felony Counts		12
Superceeding Indictment [Member] | Criminal Investigation [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Number of Felony Counts		15
Penalty for each count of alleged violation		$ 500
Total maximum penalties		6,500
Gross gain derived from alleged violation		281,000
Gross loss derived from alleged violation		$ 562,000
Alleged Obstruction of NTSB Investigation [Member] | Criminal Investigation [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Number of Felony Counts		1

[1] In March 2015, the Utility increased its accrual from $200 million at December 31, 2014 to $300 million.

[2] These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses.

[3] The Penalty Decision prohibits the Utility from recovering certain expenses and capital spending associated with pipeline safety-related projects and programs that the CPUC will identify in the final decision to be issued in the Utility’s 2015 GT&S rate case. The Utility estimates that approximately $407 million of capital spending (which include less than $1 million for remedy related capital costs) in the year ended December 31, 2015 is probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision.

[4] In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision and does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs are being expensed as incurred.

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Commitments And Contingencies (Environmental Remediation Liability Composed) (Detail) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Topock natural gas compressor station	[1]	$ 300	$ 291
Hinkley natural gas compressor station	[1]	140	158
Former manufactured gas plant sites owned by the Utility or third parties		271	257
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites		164	150
Fossil fuel-fired generation facilities and sites		94	98
Total environmental remediation liability		$ 969	$ 954

[1] See Natural Gas Compressor Station Sites below.

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Commitments And Contingencies (Environmental Remediation Contingencies) (Details) $ in Millions	Dec. 31, 2015 USD ($)
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$ 695
Utility Undiscounted Future Costs	$ 1,900
Remediation cost recovery	90.00%

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Commitments And Contingencies (Nuclear Insurance) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Long-term Purchase Commitment [Line Items]
Humboldt Bay Unit 3 potential premium obligation	$ 60
Coverage for purchased public liability insurance, per incident	375
Diablo Canyon [Member]
Long-term Purchase Commitment [Line Items]
Maximum public liability per nuclear incident under Price-Anderson Act	13,500
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act	375
Maximum total payment incurred per event under the loss sharing program	255
Maximum annual payment incurred per event under the loss sharing program	38
Diablo Canyon [Member] | Nuclear Incident [Member]
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	3,500
Diablo Canyon [Member] | Non Nuclear Incident [Member]
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	2,800
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

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Commitments And Contingencies (Third-Party Power Purchases) (Details) $ in Millions	Dec. 31, 2015 USD ($)
Long-term Purchase Commitment [Line Items]
2016	$ 3,987
2017	3,618
2018	3,341
2019	3,274
2020	3,200
Thereafter	32,552
Total	49,972
Renewable Energy Power Purchase Agreements [Member]
Long-term Purchase Commitment [Line Items]
2016	2,177
2017	2,201
2018	2,075
2019	2,087
2020	2,077
Thereafter	29,098
Total	39,715
Other Power Purchase Agreements [Member]
Long-term Purchase Commitment [Line Items]
2016	504
2017	380
2018	359
2019	290
2020	213
Thereafter	997
Total	2,743
Nuclear Fuel Purchase Commitments [Member]
Long-term Purchase Commitment [Line Items]
2016	113
2017	100
2018	96
2019	98
2020	133
Thereafter	185
Total	725
Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
2016	421
2017	150
2018	105
2019	105
2020	103
Thereafter	543
Total	1,427
Conventional Energy [Member]
Long-term Purchase Commitment [Line Items]
2016	772
2017	787
2018	706
2019	694
2020	674
Thereafter	1,729
Total	$ 5,362

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Commitments And Contingencies (Third-Party Power Purchase Agreements) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Qualifying Facilities [Member]
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase commitments, date of contract expiration, beginning date	2016
Long term contract for purchase commitments, date of contract expiration, ending date	2028
Present value of fixed capacity payments, portion classified as current liabilities	$ 19.0	$ 20.0
Present value of fixed capacity payments, portion classified as noncurrent liabilities	35.0	54.0
Capitalized asset for fixed capacity payments for corresponding assets	54.0	74.0
Capitalized asset for fixed capacity payments, accumulated amortization	$ 147.0	128.0
Renewable Energy [Member]
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase commitments, date of contract expiration, beginning date	2016
Long term contract for purchase commitments, date of contract expiration, ending date	2043
Power Purchases and Electric Capacity [Member]
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase commitments, date of contract expiration, beginning date	2016
Long term contract for purchase commitments, date of contract expiration, ending date	2033
Costs Of Power Purchase	$ 3.5	$ 3.6	$ 3.0

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Commitments And Contingencies (Gas Supply, Transportation And Storage) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Cost of natural gas purchases	$ 900	$ 1,400	$ 1,600
Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase Commitments Expiration Beginning Date	2016
Long Term Contract For Purchase Commitments Expiration Ending Date	2026

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Commitments And Contingencies (Nuclear Fuel Agreements) (Details) - Nuclear Fuel [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase Commitments Expiration Beginning Date	2016
Long Term Contract For Purchase Commitments Expiration Ending Date	2025
Payments for Nuclear Fuel	$ 128	$ 105	$ 162

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Other Commitments And Other Operating Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments And Contingencies [Abstract]
2016	$ 40
2017	41
2018	40
2019	38
2020	37
Thereafter	194
Total	390
Payments for other commitments and operating leases	$ 41	$ 42	$ 40
Property Subject To Or Available For Operating Lease Expiration Beginning Date	2016
Property Subject To Or Available For Operating Lease Expiration Ending Date	2052

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Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Income Statement) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating expenses	$ (15,325)	$ (14,640)	$ (13,836)
Interest income	9	9	9
Interest expense	(773)	(734)	(715)
Other income (expense)	117	70	40
Income Before Income Taxes	861	1,795	1,096
Income tax benefit	(27)	345	268
Income Available for Common Shareholders	874	1,436	814
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
Net change in investments (net of taxes $12, $17, and $26, at respective dates)	(17)	(25)	38
Total other comprehensive income (loss)	(18)	(39)	151
Comprehensive Income	$ 870	$ 1,411	$ 979
Weighted average common shares outstanding, basic	484	468	444
Weighted average common shares outstanding, diluted	487	470	445
Net earnings per common share, basic	$ 1.81	$ 3.07	$ 1.83
Net earnings per common share, diluted	$ 1.79	$ 3.06	$ 1.83
PG&E Corporation [Member]
Administrative service revenue	$ 51	$ 51	$ 41
Operating expenses	(53)	(53)	(42)
Interest income	1	1	1
Interest expense	(10)	(14)	(25)
Other income (expense)	30	(1)	(57)
Equity in earnings of subsidiaries	852	1,413	848
Income Before Income Taxes	871	1,397	766
Income tax benefit	3	39	48
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
Pension and other postretirement benefit plans (net of taxes of $10, $80, $72, at respective dates)	(1)	(14)	113
Net change in investments (net of taxes $12, $17, and $26, at respective dates)	(17)	(25)	38
Total other comprehensive income (loss)	(18)	(39)	151
Comprehensive Income	$ 856	$ 1,397	$ 965
Weighted average common shares outstanding, basic	484	468	444
Weighted average common shares outstanding, diluted	487	470	445
Net earnings per common share, basic	$ 1.81	$ 3.07	$ 1.83
Net earnings per common share, diluted	$ 1.79	$ 3.06	$ 1.83

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Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Balance Sheet) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash and cash equivalents	$ 123	$ 151	$ 296	$ 401
Advances to affiliates	21	20
Income taxes receivable	155	198
Other Assets, Current	347	443
Total current assets	5,822	6,389
Equipment	67,342	63,062
Accumulated depreciation	(20,619)	(19,121)
Net property, plant, and equipment	46,723	43,941
Income taxes receivable	135	91
Other	1,160	963
TOTAL ASSETS	63,339	60,127
Short-term borrowings	1,019	633
Long-term debt, classified as current	160	0
Other	1,997	1,846
Total current liabilities	6,363	5,920
Long-term debt	16,030	15,050
Other	2,326	2,218
Total noncurrent liabilities	40,148	38,207
Common stock	11,282	10,421
Reinvested earnings	5,301	5,316
Accumulated other comprehensive income (loss)	(7)	11	50
Total shareholders' equity	16,576	15,748
TOTAL LIABILITIES AND EQUITY	63,339	60,127
PG&E Corporation [Member]
Cash and cash equivalents	64	96	$ 231	$ 207
Advances to affiliates	22	31
Income taxes receivable	24	29
Other Assets, Current	1	38
Total current assets	111	194
Equipment	2	2
Accumulated depreciation	(2)	(1)
Net property, plant, and equipment	0	1
Investments in subsidiaries	16,837	16,003
Other investments	130	117
Deferred income taxes	250	260
Total noncurrent assets	17,217	16,381
TOTAL ASSETS	17,328	16,575
Accounts payable - other	3	67
Other	246	269
Total current liabilities	249	336
Long-term debt	350	350
Other	153	141
Total noncurrent liabilities	503	491
Common stock	11,282	10,421
Reinvested earnings	5,301	5,316
Accumulated other comprehensive income (loss)	(7)	11
Total shareholders' equity	16,576	15,748
TOTAL LIABILITIES AND EQUITY	$ 17,328	$ 16,575

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Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Statement Of Cash Flows) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net income		$ 888	$ 1,450	$ 828
Deferred income taxes and tax credits, net		693	690	1,075
Net cash provided by operating activities		3,753	3,677	3,427
Other		22	114	56
Net cash used in investing activities		(5,211)	(4,714)	(5,107)
Borrowings under revolving credit facilities		0	(260)	140
Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014		1,123	2,308	1,532
Long-Term Debt Repurchased		0	889	861
Common stock issued		780	802	1,045
Common stock dividends paid		(856)	(828)	(782)
Other		0	42	(41)
Net cash (used) in financing activities		1,430	892	1,575
Net change in cash and cash equivalents		(28)	(145)	(105)
Cash and cash equivalents at January 1		151	296	401
Cash and cash equivalents at December 31		123	151	296
Cash received (paid) for:
Interest, net of amounts capitalized		(684)	(633)	(623)
Income taxes, net		77	501	(41)
Noncash common stock issuances		(21)	(21)	(22)
Common stock dividends declared but not yet paid		(224)	(217)	(208)
PG&E Corporation [Member]
Net income		874	1,436	814
Depreciation and amortization		66	65	54
Equity in earnings of subsidiaries		(852)	(1,413)	(848)
Deferred income taxes and tax credits, net		10	(72)	(10)
Noncurrent income taxes receivable/payable		0	5	0
Current income taxes receivable/payable		5	(16)	20
Other		(70)	43	(20)
Net cash provided by operating activities		33	48	10
Investment in subsidiaries		(705)	(978)	(1,371)
Dividends received from subsidiaries	[1]	716	716	716
Proceeds from tax equity investments		0	368	275
Other		0	0	(8)
Net cash used in investing activities		11	106	(388)
Borrowings under revolving credit facilities		0	(260)	140
Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014		0	347	0
Long-Term Debt Repurchased		0	(350)	0
Common stock issued		780	802	1,045
Common stock dividends paid	[2]	(856)	(828)	(782)
Other		0	0	(1)
Net cash (used) in financing activities		(76)	(289)	402
Net change in cash and cash equivalents		(32)	(135)	24
Cash and cash equivalents at January 1		96	231	207
Cash and cash equivalents at December 31		64	96	231
Cash received (paid) for:
Interest, net of amounts capitalized		(9)	(15)	(23)
Income taxes, net		0	1	21
Noncash common stock issuances		21	21	22
Common stock dividends declared but not yet paid		$ 224	$ 217	$ 208

[1] Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow.

[2] In January, April, July, and October of 2015, 2014, and 2013, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

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Schedule II - Consolidated Valuation And Qualifying Accounts (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule II - Consolidated Valuation And Qualifying Accounts [Abstract]
Allowance for uncollectible accounts, Balance at Beginning of Period	[1]	$ 66	$ 80	$ 87
Allowance for uncollectible accounts, Charged to Costs and Expenses	[1]	43	41	53
Allowance for uncollectible accounts, Deductions	[1],[2]	55	55	60
Allowance for uncollectible accounts, Balance at End of Period	[1]	$ 54	$ 66	$ 80

[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.