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, 2016
☐	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 MKT LLC
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, 2016, the last business day of the most recently completed second fiscal quarter:

PG&E Corporation common stock	$31,807 million
Pacific Gas and Electric Company common stock	Wholly owned by PG&E Corporation

Common Stock outstanding as of February 7, 2017:

PG&E Corporation:	507,782,249 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 2017 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.

2016 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, 2016
AB	Assembly Bill
AFUDC	allowance for funds used during construction
ALJ	administrative law judge
ARO	asset retirement obligation
ASU	accounting standard update issued by the FASB (see below)
CAISO	California Independent System Operator
Cal Fire	California Department of Forestry and Fire Protection
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
CO2	carbon dioxide
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
DER	distributed energy resources
Diablo Canyon	Diablo Canyon nuclear power plant
DOE	U.S. Department of Energy
DOGGR	Division of Oil, Gas and Geothermal Resources
DOI	U.S. Department of the Interior
DTSC	Department of Toxic Substances Control
EMANI	European Mutual Association for Nuclear Insurance
EPA	Environmental Protection Agency
EPS	earnings per common share
EV	electric vehicle
FASB	Financial Accounting Standards Board
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
IOUs	investor-owned utility(ies)
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
MOU	memorandum of understanding
NAV	net asset value
NDTCP	Nuclear Decommissioning Cost Triennial Proceedings
NEIL	Nuclear Electric Insurance Limited
NEM	net energy metering
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
OII	order instituting investigation
ORA	Office of Ratepayer Advocates
PHMSA	Pipeline and Hazardous Materials Safety Administration
PSEP	pipeline safety enhancement plan
QF	qualifying facility
Regional Board	California Regional Water Quality Control Board, Lahontan Region

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REITS	real estate investment trust
RFO	requests for offers
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
TE	transportation electrification
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, 2016, PG&E Corporation and the Utility had approximately24,000regular employees, approximately 30 of which were employees of PG&E Corporation.  Of the Utility’s regular employees, approximately 14,000 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”).  A new SEIU collective bargaining agreement was ratified in December 2016 and is effective August 1, 2016 through December 31, 2019.  Two new agreements (Physical and Clerical) with IBEW and an agreement with ESC were ratified in 2016 and were retroactive to January 1, 2016.  They 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.  Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency.  It is possible that these regulatory filings or information included therein could be deemed to be material information.  The information contained on these websites is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC.

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 “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.

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 is a regulatory agency that regulates privately owned public utilities in California.  The CPUC consists of five commissioners 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 electric and natural gas distribution operations, electric 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.

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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.

The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports.  Under both the gas and electric programs, the SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000.  The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day.  In September 2016, the CPUC adopted improvements and refinements to its gas and electric safety citation programs.  Specifically, the final decision refines the criteria for the SED to use in determining whether to issue a citation and the amount of penalty, sets an administrative limit of $8 million per citation issued, makes self-reporting voluntary in both gas and electric programs, adopts detailed criteria for the utilities to use to voluntarily self-report a potential violation, and refines other issues in the programs.  The decision also merges the rules applicable to its gas and electric safety citation programs into a single set of rules that replaces the previous safety citation 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 establishment of energy storage procurement targets, 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.)

The Federal Energy Regulatory Commission and the California Independent System Operator

The FERC has jurisdiction over the Utility's electric 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 system 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 electric 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 violations 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 electric 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 generating 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 Nuclear Power Plant” in MD&A and Item 1A. Risk Factors below.)

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Other Regulators

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 plansand for adopting building and appliance energy efficiency requirements.

The CARB is the state agency responsible for setting and monitoring GHG and other emission limits.  The CARB is alsoresponsible 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 the Utility 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.

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 Utility 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 electric and gas rates vary depending on seasons mostly due to the influence of weather. Electricity rates increase during the summer months (May – October) because of higher demand, driven by air conditioning loads, while gas service rates generally increase during the winter months (November – March) to account for the gas peak due to heating.

During 2016, 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 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 more 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 “Regulatory Matters – 2014 – 2015 Energy Efficiency Incentive Awards” in MD&A.)

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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 or four 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 in revenue requirements for the subsequent years of the GRC period(known as “attrition years”).  Attrition year 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 other business, community, customer, environmental, and union 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. The CPUC generally conducts a GT&S rate case every three or four years. Similar to the GRC proceeding, the CPUC approves the annual revenue requirements for the first year (or “test year”) of the GT&S period and typically determines annual increases in revenue requirements for attrition years of the GT&S period. Parties in the Utility's GT&S rate case include the ORA and TURN, who generally represent the overall interests of residential customers, as well as other intervenors who represent other business, community, customer, and union interests. (For more information, see “Regulatory Matters – 2015 Gas Transmission and Storage Rate Case” in MD&A.)

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 through 2017 at 10.40%.  The CPUC 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.  On February 25, 2016, the CPUC issued a decision granting a petition for modification filed by the Utility and the other California IOUs to clarify that the CPUC’s previously adopted cost of capital adjustment mechanism would not be triggered for 2017.

On February 6, 2017, the Utility and other California IOUs entered into a MOU with the CPUC, ORA, and TURN to extend the next cost of capital application filing deadline two years to April 22, 2019 for the year 2020.  To implement the MOU, on February 7, 2016, the IOUs, ORA, and TURN filed with the CPUC a petition for modification of prior CPUC decisions addressing cost of capital.  If the petition for modification is approved as submitted it would reduce the Utility’s ROE from 10.40% to 10.25% and reset the Utility’s authorized cost of long-term debt and preferred stock beginning January 1, 2018.  The Utility’s current capital structure of 52% common equity, 47% long-term debt, and 1% preferred equity would remain unchanged.  The Utility’s cost of capital adjustment mechanism would not operate in 2017 but could operate in 2018 to change the cost of capital for 2019.  If the mechanism is activated for 2019, the Utility’s cost of capital, including its new ROE of 10.25%, will be adjusted according to the existing terms of the mechanism.  Concurrently with the petition for modification, the Utility and other California IOUs also sent a letter to the executive director of the CPUC requesting that the existing April 2017 filing due date for the 2018 cost of capital be deferred while the CPUC is considering the petition for modification.  On February 13, 2017, the executive director of the CPUC granted the request.  As extended, the Utility and the other California IOUs would file their next cost of capital applications 60 days after the effective date of the CPUC decision on the petition for modification, or April 20, 2017, whichever is later, if the CPUC does not grant the petition for modification.

The Utility expects that the CPUC may issue a decision in the first half of 2017.  (For more information, see “Regulatory Matters –CPUC Cost of Capital” in MD&A.)

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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.  (For more information, see “Regulatory Matters – FERC Transmission Owner Rate 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 electrical capacity 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 certain electricity procured from third parties into 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 bundled customer procurement plans based on long-term demand forecasts.  The Utility’s most recent bundled customer procurement plan was approved in October 2015, and will remain in effect until the plan is superseded by a subsequent CPUC-approved plan. 

California law allows electric utilities to recover the costs incurred in compliance with their CPUC-approved bundled customer procurement plans without further after-the-fact reasonableness review by the CPUC.  The CPUC may disallow costs associated with electricity purchases if 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.  Additionally, the cost of replacement power procured due to unplanned outages at Utility owned generation facilities may be disallowed.

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 more information, see “Electric Utility Operations – Electricity Resources” below as well as Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

Natural Gas Procurement, Storage, and Transportation Costs

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 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 for its core gas portfolio, through its retail gas rates, 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. 

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The core procurement incentive mechanism protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs for its core gas portfolio.  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 these 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 National Energy Board, a Canadian regulatory agency.  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.

On August 11, 2016, the Utility submitted an application to the CPUC to retire Diablo Canyon at the expiration of its current operating licenses in 2024 and 2025.  (For more information, see “Legislative and Regulatory Initiatives” in MD&A.)

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.

The Utility has continued to invest in its visionfor a future electric gridwhich will allow customers to choose new, advanced energy supply technologies and services to meet their needs consistent with safe, reliable and affordable electric service.  In addition, in December 2016, the CPUC issued a final decision establishing a three-year EV program for the Utility to deploy up to 7,500 charging stations. (For more information, see “Legislative and Regulatory Initiatives” in MD&A.)

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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 2016 represented by each major electricity resource, and further discussed below.

Total 2016 Actual Electricity Generated and Procured –68,441GWh (1):

		Percent of Bundled Retail Sales
Owned Generation Facilities
	Nuclear		24.2	%
	Small Hydroelectric		1.3	%
	Large Hydroelectric		9.8	%
	Fossil fuel-fired		7.3	%
	Solar		0.5	%
	Total				43.1	%
Qualifying Facilities
	Renewable		2.6	%
	Non-Renewable		5.1	%
	Total				7.7	%
Irrigation Districts and Water Agencies
	Large Hydroelectric		0.5	%
	Total				0.5	%
Other Third-Party Purchase Agreements
	Renewable		28.4	%
	Large Hydroelectric		2.1	%
	Non-Renewable		4.8	%
	Total				35.3	%
Others, Net(2)					13.4	%
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 an RPS that requires 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 into law.  SB 350 became effective January 1, 2016, and 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 three-year compliance period thereafter, unless changed by legislative action.  SB 350 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 is required to open a new rulemaking proceeding to adopt regulations to implement the higher renewable targets.   

As indicated below, the Utility’s application and joint proposal to retire Diablo Canyon include a voluntary increase in the Utility’s target for RPS-eligible resources to 55%, effective in 2031 through 2045, as compared to the state’s goal of 50% renewables.(For more information, see “Legislative and Regulatory Initiatives” in MD&A.)

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 2016, 32.8%of the Utility’s energy deliveries were from renewable energy sources, exceeding the annual RPS target of 23.3%.  Approximately 28.4% of the renewable energy delivered to the Utility’s customers was purchased from non-QF third parties.  Additional renewable resources were provided by QFs (2.6%), the Utility’s small hydroelectric facilities (1.3%), and the Utility’s solar facilities (0.5%).

The total 2016 renewable deliveries shown above were comprised of the following:

Type	GWh	Percent of Bundled Retail Sales
Biopower	2,958	4.3%
Geothermal	3,705	5.4%
Small Hydroelectric	1,800	2.6%
Solar	8,598	12.6%
Wind	5,419	7.9%
Total	22,480	32.8%

Energy Storage.  As required by California law, the CPUC has opened a proceeding to establish a multi-year energy storage procurement framework, including energy storage procurement targets to be achieved by each load-serving entity under the CPUC jurisdiction, including the Utility.  Under the adopted energy storage procurement framework, the Utility is required to procure 580 MW of qualifying storage capacity by 2020, with all energy storage projects required to be operational by the end of 2024.

The CPUC also adopted biennial interim storage targets for the Utility, beginning in 2014 and ending in 2020.  Under the adopted framework, the Utility is required to conduct biennial competitive RFOs to help meet its interim storage targets. 

The Utility conducted an RFO in 2014. The Utility’s 2014 energy storage target was 90 MW, some of which the Utility met through already existing projects, or projects anticipated to result from other CPUC proceedings.  As a result of the 2014 RFO, 70 MW of transmission and distribution contracts have been approved by the CPUC.  Contracts for 6MW were rejected by the CPUC, including a behind-the-meter project.  Additionally, contracts for 13 MW were withdrawn by the Utility. 

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The Utility’s 2016 energy storage target is 120 MW.  On November 30, 2016, the Utility issued its 2016 RFO.  The Utility must submit all executed contracts from the 2016 RFO to the CPUC for approval by December 1, 2017.  The Utility expects to increase the amount of storage it is attempting to procure in its 2016 RFO by the shortfall from the 2014 target.

Owned Generation Facilities.  At December 31, 2016, 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 large photovoltaic facilities are Five Points solar station (15 MW), Westside solar station (15 MW), Stroud solar station (20 MW), Huron solar station (20 MW), Cantua solar station (20 MW), Giffen solar station (10 MW), Gates solar station (20 MW), West Gates solar station (10 MW) and Guernsey solar station (20 MW).  All of these facilities are located in Fresno County, except for 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, 2016, 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 92 electric transmission substations with a capacity of approximately 64,600 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 the Fresno, Madera and Kings counties area.  The CAISO has stated that the 2022 in-service date for the 70-mile line has been postponed, and has placed the project on hold.  The Utility has stopped all work on the project pending a decision from the CAISO that could defer or cancel the project.  A decision by the CAISO is expected by March 2018.In addition, as a part of the CAISO's 2016-2017 planning efforts, the CAISO conducted a review of a number of local area low voltage transmission projects in the Utility’s service territory that were predominantly load forecast driven.  As a result of the review, the CAISO found that a number of lower-voltage transmission projects were no longer required and  recommended cancelling or requiring further review in the 2017-2018 planning cycle. 

On March 29, 2026 the Utility entered into an agreement with TransCanyon, LLC, a joint venture between subsidiaries of Berkshire Hathaway Energy and Pinnacle West Capital Corporation, to jointly pursue competative transmission opportunities solicited by the CAISO.  The Utility and TransCanyon intend to jointly engage in the development of future transmission infastructure and compete to develop, build, own and operate transmission projects approved by the CAISO.

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Throughout 2016, 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 secure access to renewable generation resources and 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.

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), 59 transmission switching substations, and 606 distribution substations, with a capacity of approximately 31,800 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 2016 the Utility commenced operations in a new electric distribution control center facilityin Concord, California; along with the existing distribution control centers in Rocklin and Fresno, California, these control centers form a key part of the Utility’s efforts to create a smarter, more resilient grid.

In 2016, 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 89 circuits were outfitted with this equipment, bringing the total deployment to 789 of the Utility’s 3,200 distribution circuits. The Utility plans to continue performing work to improve the reliability and safety of its electricity distribution operations in 2017.

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Electricity Operating Statistics

The following table shows certain of the Utility’s operating statistics from 2014 to 2016 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 2016, 2015 and 2014.

		2016		2015		2014
Customers (average for the year)		5,349,691		5,311,178		5,276,025
Deliveries (in GWh) (1)		83,017		85,860		86,303
Revenues (in millions):
Residential	$	5,409	$	5,032	$	4,784
Commercial		5,396		5,278		5,141
Industrial		1,525		1,555		1,543
Agricultural		1,226		1,233		1,172
Public street and highway lighting		80		83		79
Other (2)		(68)		(84)		(172)
Subtotal		13,568		13,097		12,547
Regulatory balancing accounts (3)		297		560		1,109
Total operating revenues	$	13,865	$	13,657	$	13,656
Selected Statistics:
Average annual residential usage (kWh)		6,115		6,294		6,458
Average billed revenues per kWh:
Residential	$	0.1887	$	0.1719	$	0.1603
Commercial		0.1716		0.1640		0.1585
Industrial		0.0990		0.0973		0.0998
Agricultural		0.1814		0.1610		0.1516
Net plant investment per customer	$	7,195	$	6,660	$	6,339

(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. 

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 90% of core customers, representing nearly 78% 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.

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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 can also receive natural gas from 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 2016, the Utility purchased approximately 307,100 MMcf of natural gas (net of the sale of excess supply of gas).  Substantially all of this natural gas was purchased under contracts with a term of one year or less.  The Utility’s largest individual supplier represented approximately 14% of the total natural gas volume the Utility purchased during 2016.

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, 2016, 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 natural 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.  Similarly, the Utility has firm transportation agreements with Transwestern Pipeline Company, LLC and El Paso Natural Gas Company to transport natural gas from supply points in the Southwestern United States 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.

As of December 31, 2016 the Utility had installed 268 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. The NTSB closed that recommendation in 2015. The final safety recommendation, considered open and acceptable by the NTSB, involves ensuring that all high consequence pipeline mileage in the Utility’s gas transmission system has been hydrostatically tested. As of December 31, 2016, the Utility has hydrostatically tested about 840 miles and completed the majority of this safety recommendation. The Utility currently plans to complete the NTSB recommendation by 2022 for the remaining approximately 28 aggregate pipeline miles (involving hundreds of primarily short pipeline segments that include tie-in pieces, fittings or smaller diameter off-takes from the larger transmission pipelines).

In addition, in 2016, the Utility inspected 260 miles of transmission pipeline using in-line inspection tools and upgraded an additional 107 miles of transmission pipeline to allow for the use in-line inspection tools, replaced 127 miles of distribution main, and completed the installation of over 25,000 line makers to more easily identify the locations of gas pipelines.

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Natural Gas Operating Statistics

The following table shows the Utility's operating statistics from 2014 through 2016 (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 2016, 2015 and 2014.

		2016		2015		2014
Customers (average for the year)		4,442,379		4,415,332		4,394,283
Gas purchased (MMcf)		208,260		209,194		202,215
Average price of natural gas purchased	$	1.83	$	2.11	$	4.09
Bundled gas sales (MMcf):
Residential		149,483		144,885		143,514
Commercial		46,507		43,888		42,080
Total Bundled Gas Sales		195,990		188,773		185,594
Revenues (in millions):
Bundled gas sales:
Residential	$	1,968	$	1,816	$	1,683
Commercial		439		403		419
Other		149		125		51
Bundled gas revenues		2,556		2,344		2,153
Transportation service only revenue		800		649		662
Subtotal		3,356		2,993		2,815
Regulatory balancing accounts		446		183		617
Total operating revenues	$	3,802	$	3,176	$	3,432
Selected Statistics:
Average annual residential usage (Mcf)		36		35		34
Average billed bundled gas sales revenues per Mcf:
Residential	$	13.10	$	12.53	$	11.72
Commercial		9.45		9.18		9.96
Net plant investment per customer	$	2,808	$	2,573	$	2,468

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 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 and businesses which do not affirmatively elect to continue to receive electricity from a utility.

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 intended 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, generally through eminent domain.These same entities may, and sometimes do, construct duplicate distribution facilities to serve existing or new Utility customers.

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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.These factors result in a shift of cost responsibility for grid and related services to other customers of the Utility.  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 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 CO­2and 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 ratemaking mechanism described in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

Hazardous Waste Compliance and Remediation

The Utility's facilities are subject tovarious regulations adopted by the U.S.  Environmental Protection Agency, includingthe 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 other federal agencies responsible for implementing 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, monitoring and paying for the harm caused to natural resources, and paying for the costs of health studies.

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.

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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 were required to submit final plans to comply with these regulations by September 2016, but were permitted to 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 40% below1990 levels by 2030.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.

With the change in federal administration from President Barack Obama to President Donald Trump, there is significant uncertainty with regard to what further actions may occur regarding climate change at the federal level.  The new administration has indicated that it intends to revoke the Clean Power Plan regulations and possibly withdraw from international efforts to combat climate change.  Upon taking office, President Trump issued an executive order to freeze all regulations issued in the 60 days preceding his inauguration and directed the EPA and the White House to remove climate change-relatedmaterials and web pages, pending further review.  It is assumed that the new administration also will take action to suspend all climate related regulatory and funding activities.  In light of the potential policy reversal at the federal level, the State of California has indicated that it intends to continue and enhance its leadership on climate change nationally and globally. 

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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.  Emitters can 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.  Additionally, Senate Bill 32 (2016) requires that CARB ensure a 40% reduction in greenhouse gases by 2030 compared to 1990 levels.  CARB is currently considering regulatory amendments to the cap-and-trade program to extend the program’s authority to 2030.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 2016, 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, including forming an officer-level coordinating committee to govern and oversee the Utility’s activities.  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 changes 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.

Notwithstanding the current high snowpack, climate scientists predict that climate change will result in varying temperatures and levels of precipitation in the Utility’s service territory.  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 2015 totaled more than 54 million metric tonnes of CO­2 equivalent, two-thirds of which came from customer natural gas use.  The following table shows the 2015 GHG emissions data the Utility reported to the CARB under AB 32.PG&E Corporation and the Utility also publish additional GHG emissions data in their annual Corporate Responsibility and Sustainability Report.

Source	Amount (metric tonnes CO2 equivalent)
Fossil Fuel-Fired Plants (1)	2,875,176
Natural Gas Compressor Stations and Storage Facilities (2)	362,472
Distribution Fugitive Natural Gas Emissions	676,458
Customer Natural Gas Use  (3)	43,022,557

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

(2) Including, but not limited to, 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 2015 as compared to the national average for electric utilities:

	Amount (pounds of CO2 per MWh)
U.S. Average (1)	1,143
Pacific Gas and Electric Company (2)	405

(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 40% of the Utility’s delivered electricity in 2015.  PG&E Corporation and the Utility also publish air emissions data in their annual Corporate Responsibility and Sustainability Report.

	2015	2014
Total NOx Emissions (tons)	160	141
NOx Emissions Rate (pounds/MWh)	0.01	0.01
Total SO2 Emissions (tons)	17	14
SO2 Emissions Rate (pounds/MWh)	0.0011	0.0010

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%.  The policy also provided for an alternative compliance approach for nuclear plants if certain criteria were met.  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.  The reportaddressed feasibility, costs and timeframes to install alternative technologies at Diablo Canyon, such as cooling towers.  The Utility’s Diablo Canyon operations must be in compliance with the California Water Board’s policy by December 31, 2024.

On June 20, 2016, the Utility entered into a joint proposal with certain parties to retire Diablo Canyon at the expiration of its current operating licenses in 2024 and 2025, and replace it with a GHG-free portfolio of energy efficiency, renewables and energy storage.  As a result of the planned retirement, the California Water Board will no longer need to address alternative compliance measures for Diablo Canyon.  Beginning in 2017, as required under the policy, the Utility will pay an annual interim mitigation fee until operations cease in 2024 and 2025.

Additionally, the Utility expects that its decision to retire Diablo Canyon will affect the terms of a final settlement agreementbetween the Utility, the Central Coast Water Board and the California Attorney General’s Office regarding the thermal component of the plant’s once-through cooling discharge.  (For more information, 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 (“DOJ”) 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. Through 2016, the Utility has been awarded an additional $99 million through these annual submissions, including $28 million for costs incurred between June 1, 2014 and May 31, 2015. The claim for the period June 1, 2015 through May 31, 2016 is currently 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; an extension of the agreement for costs through 2019 is pending DOJ approval. Costs beyond 2016 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 Related to the Outcome of Enforcement Matters, Investigations, and Regulatory Proceedings

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially affected by the ultimate amount of third-party liability that the Utility incurs in connection with the Butte fire.

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures. Cal Fire’s report concluded that the wildfire was caused when a Gray Pine tree contacted the Utility’s electric line which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. In a press release also issued on April 28, 2016, Cal Fire indicated that it will seek to recover firefighting costs in excess of $90 million from the Utility.

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California for Sacramento County. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council had previously authorized the coordination of all cases in Sacramento County. As of December 31, 2016, complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 1,950 individual plaintiffs representing approximately 950 households and their insurance companies. These complaints are part of or are in the process of being added to the two master complaints. Plaintiffs seek to recover damages and other costs, principally based on inverse condemnation and negligence theories of liability. The number of individual complaints and plaintiffs may increase in the future.

In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees without having been found negligent, through the theory of inverse condemnation.  In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent.The Utility believes that it is probable that it will incur a loss of at least $750 million for all potential damages described above. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of approximately $900 million.  Such insurance coverage is subject to the terms and limitations of the available policies and may not be sufficient to cover the Utility’s ultimate liability.

The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional discovery from the plaintiffs and results from the ongoing mediation and settlement process, management estimates and assumptions regarding the financial impact of the Butte fire may change. A change in management’s estimates or assumptions could result in an adjustment that could have a material impact on PG&E Corporation’s and the Utility’s financial condition and the results of operations during the period such change occurred.

If the Utility records losses in connection with claims relating to the Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected in the reporting periods during which additional charges are recorded, depending on whether the Utility is able to record or collect insurance recoveries in amounts sufficient to offset such additional accruals. (For more information, see “Enforcement and Litigation Matters” in Item 7. MD&A and in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

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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 and requests for information.  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 a potential settlement or litigated outcome of the CPUC’s investigation of the Utility’s compliance with the CPUC’s rules regarding ex parte communications.  While on October 14, 2016, the Cities of San Bruno and San Carlos, ORA, the SED, TURN, and the Utility submitted a status report to the CPUC which proposed an update to the framework for resolving the proceeding and included a total of 164 communications in the scope of the proceeding, the Utility expects that the other parties may argue that the number of violations exceeds the 164 communications referenced in the status report either because a single communication may have violated more than one rule or because they believe some of the material provided during discovery constitutes impermissible ex parte communications.  The Utility expects to contest many of these assertions.  If the matter does not settle, the CPUC will determine which communications included within the scope of the proceeding were in violation of its rules.  The CPUC will also determine whether to impose penalties or other remedies, as a result of a potential settlement or otherwise.  The CPUC can impose fines up to $50,000 for each violation, and up to $50,000 per day if the CPUC determines that the violation was continuing.  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 broad discretion in determining whether violations are continuing and the amount of penalties to be imposed.  While it is uncertain how the CPUC will calculate the number of violations or the penalty for any violations, such fines or penalties could be significant and materially affect PG&E Corporation’s and the Utility’s liquidity and results of operations. (See the discussion under the heading “Regulatory Matters” in MD&A.)

The Utility also is a target of a number of investigations and government requests for information.  In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel.In addition, in October 2016, the Utility received a grand jury subpoena and letter from the U.S. Attorney for the Northern District of California advising that the Utility is a target of a federal investigation regarding possible criminal violations of the Migratory Bird Treaty Act and conspiracy to violate the act.  The Utility was also contacted by certain other federal agencies with requests for information.  While the Utility believes that these requests for information are routine, their outcome is uncertain.  The Utility also is unable to predict the outcome of pending investigations, including whether any charges will be brought against the Utility.

If these investigations or requests for information 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, a negative 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.  

The Utility may incur fines and penalties in connection with the Utility’s efforts to identify and remove encroachments from transmission pipeline rights of way and the Penalty Decision.  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 practices for 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 a next phase, if any, would 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; compliance with CPUC general orders or other applicable CPUC decisions or regulations; federal electric reliability standards; and environmental compliance.  CPUC staff could impose penalties 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.  

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PG&E Corporation’s and the Utility’s future financial results could be materially affected by the conviction of the Utility in the federal criminal proceeding and by the debarment proceeding.

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act.  On January 26, 2017, the court issued a judgment of conviction against the Utility.  The court sentenced the Utility to a five-year corporate probation period, oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service. The Utility has decided not to appeal the convictions.

The probation includes a requirement that the Utility not commit any local, state or federal crimes during the probation period.  As part of the probation, the Utility is required to retain a third-party monitor.  The goal of the monitorship will be to prevent the criminal conduct with respect to gas pipeline transmission safety that gave rise to the conviction.  To that end, the goal of the monitor will be to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of the gas transmission pipeline system, performs appropriate integrity management assessments on its gas transmission pipelines, and maintains an effective ethics and compliance program and safety related incentive program.

After an initial assessment is conducted and an initial report is prepared by the monitor, the monitor will prepare reports on a semi-annual basis setting forth the monitor’s continued assessment and making recommendations consistent with the goals and scope of the monitorship.  The Utility expects that the monitor will be retained before the end of the second quarter of 2017.

At December 31, 2016, PG&E Corporation and the Utility’s Consolidated Balance Sheets included a $3 million accrual in connection with this matter.  The Utility could incur material costs and additional penalties, not recoverable through rates, in the event of non-compliance with the terms of its probation and in connection with the monitorship (including but not limited to the monitor’s compensation or costs resulting from recommendations of the monitor).

Also, in September 2015, the Utility was notified that the DOI had initiated an inquiry into whether the Utility should be suspended or debarred from entering into federal procurement and non-procurement contracts and programs citing the San Bruno explosion and indicating, as the basis for the inquiry, alleged poor record-keeping, poor identification and evaluation of threats to gas lines and obstruction of the NTSB’s investigation.  On December 21, 2016, the Utility and the DOI entered into an interim administrative agreement that reflects the DOI’s determination that the Utility remains eligible to contract with federal government agencies while the DOI determines whether any further action is necessary to protect the federal government’s business interests.  The agreement will be effective until superseded by an amended agreement or determination.  The agreement also provides that the DOI is still conducting a review to determine whether the Utility has an effective compliance and ethics program and that the DOI is required to use its best efforts to complete its review before the end of 2017.  If the DOI determines that the Utility’s program is not generally effective in preventing and detecting criminal conduct, the Utility may be required to enter into an amended administrative agreement and implement remedial and other measures, such as a requirement that the Utility’s natural gas operations and/or compliance and ethics programs be supervised by one or more independent third party monitor(s).

The Utility’s conviction and the outcome of the debarment proceeding 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 argue that the Utility should not be allowed to recover costs that the parties allege are somehow related to the criminal charges on which the Utility was found guilty.  They could also result in increased regulatory or legislative scrutiny with respect to various aspects of how the Utility’s business is conducted or organized.  As discussed under the heading “Regulatory Matters”in Item 7. MD&A, the SED continues evaluating PG&E Corporation’s andthe Utility’sorganizational culture and governance in the CPUC’s pending investigation to examine the Utility’s safety culture.

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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 reasonable 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 as a result of the Utility’s convictionin the federal criminal trial), 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.

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, underground gas storage, 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 initiatives 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 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, fires, 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. 

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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 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.

Further, PG&E Corporation’s and the Utility’s financial results could be affected by the loss of Utility customers and decreasing bundled load 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 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 above market 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 became effective for new NEM customers of the Utility in December 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 bills 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.   

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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, as well as costs related to rights-of-way and legal and regulatory costs.  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 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.

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 confidence in management’s ability to execute its business strategy and restore a constructive regulatory environment, which could adversely impact PG&E Corporation’s stock price.  Further, the market price of PG&E Corporation common stock could decline materially depending on the outcome of these matters.  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 in connection with the terms of the probation or monitorship, the pending CPUC investigations, or other enforcement matters, it would require incremental 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%.

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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, or may not become available at a reasonable cost, or available at all.

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;  

● 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;  

● a prolonged 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-based paint from the Utility’s facilities, and leaking or spilled insulating fluid from electrical equipment; and  

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● 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 the Butte fire.  (See “PG&E Corporation and the Utility may incur material liability in connection with Butte Fire” above.)  Additionally, on January 12, 2017, a residential structure fire occurred in Yuba City, California resulting in the collapse of the house and injuries to two persons inside the house.  The CPUC, a third-party engineering firm, and local fire and police officials are investigating the origin and cause of the incident.  The Utility may incur material costs, including as a result of these investigations or any proceedings that could be commenced in connection with this incident. 

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.

Further, California law includes a doctrine of inverse condemnation that is routinely invoked in California for wildfire damages. Inverse condemnation imposes strict liability (including liability for attorneys’ fees) for damages and takings as a result of the design, construction and maintenance of utility facilities, including its electric transmission lines.  As a result of the strict liability standard applied to wildfires, recent losses recorded by insurance companies, the risk of increase of wildfires including as a result of the ongoing drought, and the Butte fire, the Utility may not be able to obtain sufficient insurance coverage in the future at comparable cost and terms as the Utility’s current insurance coverage, or at all.  In addition, the Utility is unable to predict whether it would be allowed to recover in rates the increased costs of insurance or the costs of any uninsured losses.

If the amount of insurance is insufficient or otherwise unavailable, or if the Utility is unable to recover in rates the costs of any uninsured losses, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected.

The Utility’s operational and information technology systems could fail to function properly or be improperly accessed or damaged by third parties (including cyber-attacks and physical acts) or damaged by 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. All of the Utility’s operational and technology systems and network infrastructure are vulnerable to disability or failures in the event of cyber-attacks and physical acts.  Cyber-attacks are increasingly sophisticated and may include computer hacking, viruses, malware, social engineering, denial of service attacks, ransomware, destructive malware, or other means of disruption, destruction, or unauthorized access, acquisition or control.  In addition, hardware, software, or applications the Utility develops or procures from third parties may contain defects in design or manufacture or other problems that could unexpectedly compromise information security.  Physical attacks may include acts of sabotage, acts of war, acts of terrorism, or other physical acts.  The Utility’s operational and information technology systems and networks are deemed critical infrastructure, and any failure or decrease in their functionality could, among other things, cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to generate, transport, deliver and store energy and gas, or otherwise operate in the most efficient manner or at all, undermine the Utility’s performance of critical business functions, damage the Utility’s assets or operations or those of third parties, and lead to reputational harm.  As a result, such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, investigations, and regulatory actions that could result in fines and penalties, and loss of customers, any of which could have a material effect on PG&E Corporation’s and the Utility’s financial condition and results of operations.

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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 host, maintain, modify, and update its systems and these third-party vendors could cease to exist, fail to establish adequate processes to protect the Utility’s systems and information, or experience internal or external security incidents. Any incidents, disruptions or deficiencies in existing systems, or disruptions, delays or deficiencies in the modification of existing systems or implementation of new systems could result in increased costs, the inability to track or collect revenues, or diversion of management’s and employees’ attention and resources, or negatively affect the Utility’s ability to maintain effective financial controls or 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. A data breach involving theft, improper disclosure, or other unauthorized access to or acquisition of confidential information could subject the Utility to penalties for violation of applicable privacy laws, claims by third parties, and enforcement actions by government agencies.  It could also reduce the value of proprietary information, and harm the Utility’s reputation.

The Utility and its third party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to the Utility’s information technology systems, or confidential data, or to disrupt the Utility’s operations.  None of these attempts or breaches has individually or in the aggregate resulted in a security incident with a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations.  Despite implementation of security and control measures, there can be no assurance that the Utility will be able to prevent the unauthorized access to its systems, infrastructure, or data, or the disruption of its operations, either of which could materially affect PG&E Corporation’s and the Utility’s financial condition and results of operations. 

While the Utility maintains cyber liability insurance that covers certain damages caused by cyber incidents, there is no guarantee that adequate insurance will continue to be available at rates the Utility believes are reasonable or that the costs of responding to and recovering from a cyber incident will be covered by insurance or recoverable in rates.

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.)

On August 11, 2016, the Utility submitted an application to the CPUC to retire Diablo Canyon at the expiration of its current operating licenses in 2024 and 2025 and replace it with a portfolio of energy efficiency and GHG-free resources.  The application includes a joint proposal between the Utility and certain interested parties, entered into on June 20, 2016.  However, 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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In addition, in order to retain highly skilled personnel necessary to safely operate Diablo Canyon during the remaining years of operations, the Utility will incur costs in connection with (i) an employee retention program to ensure adequate staffing levels at Diablo Canyon, and (ii) an employee retraining and development program,to facilitate redeployment of a portion of Diablo Canyon personnel to the decommissioning project and elsewhere in the company. The Utility currently estimates that the additional cost of the employee retention program and the employee retraining and development program will be approximately $350 million. The Joint Proposal seeks confirmation from the CPUC that these costs will be recovered through the Utility’s nuclear decommissioning electric rates. The employee retention and retraining and development programs are subject to bargaining with the Utility’s labor unions. The Utility will also incur costs in connection with an employee severance program. The severance program was previously approved by the CPUC in prior nuclear decommissioning ratemaking proceedings.

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, 2016, the Utility’s unrecovered investment in Diablo Canyon was $1.7 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.If the Utility obtains contingent approvals referred to herein that will result in retiring Diablo Canyon at the end of the current NRC operating licenses, the Utility will not be required to install cooling towers or implement alternative measures in order to comply with the California State Water Board Once-Through Cooling Water Policy, thus eliminating the regulatory uncertainty regarding the measures that could have been imposed on the Utility or of incurring a material charge related thereto.  Even if the Utility is ultimately not required to install cooling towers, under the State Water Board’s interim mitigation measures applicable to Diablo Canyon’s operations prior to 2025, starting in 2016, it will be required to make payments to the California Coastal Conservancy to fund various environmental mitigation projects, that the Utility does not expect to exceed $5 million per year. 

On June 28, 2016 the California State Lands Commission approved an extension of the Utility’s leases of coastal land occupied by the water intake and discharge structures for the nuclear generation units at Diablo Canyon, to run concurrently with Diablo Canyon’s current operating licenses.  The Utility will be required to obtain an additional lease extension from the State Lands Commission to cover the period of time necessary to decommission the facility.  The State Lands Commission and California Coastal Commission will evaluate appropriate environmental mitigation and development conditions associated with the decommissioning project, the costs of which could be substantial.

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.  (For more information, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

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.

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.

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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.  While snowpack in the Sierra Nevada Mountains has been at higher than normal levels this winter, California has experienced ongoing drought in the past. If temperatures and the levels of precipitation in the Utility’s service territory continue to change, that could impact the levels of snowpack in the Sierra Nevada Mountains. As a result, the Utility’s hydroelectric generation could change and the Utility would need to consider managing or acquiring additional generation.

If the Utility increases its 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

PG&E Corporation’s and the Utility’s financial results could be materially affected as a result of political and legislative developments.

The Utility’s financial results could be materially affected as a result of the recent change in federal administration from President Barack Obama to President Donald Trump.  For example, the new administration has indicated tax reform as a priority.  Tax reform outlines produced by both President Trump and the Tax Reform Task Force include proposals related to federal tax rates, deductions for state income taxes (and potentially property tax), interest expense deduction, capital expenditure deduction, and expensing plant.  It is unclear what tax reform may be ultimately adopted.  It is generally expected that a tax reform bill will be introduced in early 2017.

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. 

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.

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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 million square feet of real property, including 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 167,000 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 issued a decision in its investigative enforcement proceedings against the Utility to impose total penalties of $1.6 billion on the Utility after determining that the Utility had committed numerous violations of laws and regulations related to its natural gas transmission operations 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.  In January 2016, the CPUC closed the investigative proceedings.  The total penalty included (1) a $300 million fine, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million.

The Utility refunded the $400 million to its customers in the second quarter of 2016 and paid the $300 million fine in the third quarter of 2015.  On December 1, 2016, the CPUC approved a final phase two decision in the Utility’s 2015 GT&S rate case, which applies $689 million of the $850 million penalty to capital expenditures.  The Utility is precluded from including these capital costs in rate base.  The final phase two decision also approves the Utility’s list of programs and projects that meet the CPUC’s definition of “safety related,” the costs of which are to be funded through the $850 million penalty. For more information, see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

Federal Criminal Trial

On June 14, 2016, a federal criminal trial against the Utility began in the United States District Court for the Northern District of California, in San Francisco, on 12 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, and one felony count charging that the Utility obstructed the NTSB investigation into the cause of the San Bruno accident.  On July 26, 2016, the court granted the government’s motion to dismiss one count alleging that the Utility knowingly and willfully failed to retain a strength test pressure record with respect to a distribution feeder main, thereby reducing the total number of counts from 13 to 12.

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On August 9, 2016, the jury returned its verdict.  The jury acquitted the Utility on all six of the record-keeping allegations but found the Utility guilty on six felony counts that include one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act. 

On January 26, 2017, the court issued a judgment of conviction sentencing the Utility to a five-year corporate probation period, oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service.  The Utility has decided not to appeal the convictions.  The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period.  As part of the probation, the Utility is required to retain a third-party monitor.  The goal of the monitorship will be to prevent the criminal conduct with respect to gas pipeline transmission safety that gave rise to the conviction.  To that end, the goal of the monitor will be to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of the gas transmission pipeline system, performs appropriate integrity management assessments on its gas transmission pipelines, and maintains an effective ethics and compliance program and safety related incentive program.

After an initial assessment is conducted and an initial report is prepared by the monitor, the monitor will prepare reports on a semi-annual basis setting forth the monitor’s continued assessment and making recommendations consistent with the goals and scope of the monitorship.  The Utility expects that the monitor will be retained before the end of the second quarter of 2017.  For more information, see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8 and Item 1A. Risk Factors.

Litigation Related to the San Bruno Accident and Natural Gas Spending

As of December 31, 2016, there were seven 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 theSan Bruno Fire Derivative Casesand are pending in the Superior Court of California, County of San Mateo.The remaining three cases are Tellardin v. Anthony F. Earley, Jr.,. et al.,Iron Workers Mid-South Pension Fund v. Johns, et al., and Bushkin v. Rambo et al.

On December 8, 2015, the California Court of Appeal issued a writ of mandate to the Superior Court of California, San Mateo County, ordering the court to stay all proceedings in the four consolidated San Bruno Fire Derivative Cases pending conclusion of the federal criminal proceedings against the Utility.On November 16, 2016, counsel in the four consolidated San Bruno Fire Derivative cases, as well as counsel in the Tellardin action, appeared for a status conference in the San Mateo Superior Court. The court reaffirmed that all proceedings in these actions were stayed until the conclusion of the Utility’s federal criminal proceeding, at which point they were directed to meet and confer and report back to the court.  The parties completed a mediation session on December 8-9, 2016 and continue discussions about the potential resolution of the matter.  These actions remain stayed.

Bushkin v. Rambo et al., pending in the United States District Court for the Northern District of California, has been designated by the plaintiff as related to the pending shareholder derivative suit Iron Workers Mid-South Pension Fund v. Johns, et al., discussed below. The plaintiff in the Bushkin lawsuit has agreed that this case should be stayed pending conclusion of the federal criminal trial against the Utility and, on May 3, 2016, the judge entered a stipulated order staying the case. The order also provides that the parties should meet and confer within 30 days after the criminal trial concludes and provide the court a status update. Despite the stay of his complaint, on June 20, 2016 the Bushkin plaintiff filed a petition in the Superior Court of California, San Francisco County, seeking to enforce the plaintiff’s claimed right as a shareholder to inspect certain PG&E Corporation accounting books and records pursuant to section 1601 of the California Corporations Code. On July 25, 2016, PG&E Corporation filed a motion to stay plaintiff’s petition until the appellate stay of the San Bruno Fire Derivative Cases has been lifted, or, in the alternative, a demurrer asking the court to dismiss plaintiff’s petition. On August 29, 2016, the San Francisco Superior Court granted PG&E Corporation’s motion, and indicated that plaintiff’s petition was stayed pending resolution of the criminal matter against the Utility.  On January 13, 2017, the parties submitted a joint case management statement advising the court that, because the Utility had not yet been sentenced, the case should remain stayed until at least March 10, 2017, when the parties will advise the court of further developments.While the Utility was sentenced in the federal criminal proceeding on January 26, 2017, this matter remains stayed until at least March 10, 2017.

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The Iron Workers action pending in the United States District Court for the Northern District of California has been stayed pending the resolution of the San Bruno Fire Derivative Cases. On May 5, 2016, the court ordered the parties to meet and confer within 30 days after the criminal trial concludes and provide the court a status update. At the court’s request, on August 22, 2016, the parties filed a statement requesting that the case continue to be stayed until resolution of the San Bruno Fire Derivative Cases. On August 31, 2016, the court set a case management conference for September 30, 2016, and requested the parties to file a joint case management conference statement by September 23, 2016. On September 30, 2016, the court decided to continue the stay pending the resolution of the federal criminal proceeding against the Utility and ordered the parties to submit a joint status report on or before March 15, 2017.This matter remains stayed until at least March 15, 2017.

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

Butte Fire Litigation

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California.  On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfire.  According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures.  Cal Fire’s report concluded that the wildfire was caused when a Gray Pine tree contacted the Utility’s electric line which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.  In a press release also issued on April 28, 2016, Cal Fire indicated that it will seek to recover firefighting costs in excess of $90 million from the Utility.

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California for Sacramento County.  Subrogation insurers also filed a separate master complaint on the same date.  The California Judicial Council had previously authorized the coordination of all cases in Sacramento County.  As of December 31, 2016, complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 1,950 individual plaintiffs representing approximately 950 households and their insurance companies.  These complaints are part of or are in the process of being added to the two master complaints.  Plaintiffs seek to recover damages and other costs, principally based on inverse condemnation and negligence theories of liability.  The number of individual complaints and plaintiffs may increase in the future. 

The Utility continues mediating and settling cases.  The next case management conference is scheduled for March 2, 2017.

In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees without having been found negligent, through the theory of inverse condemnation.  In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent.  The Utility believes it was not negligent; however, there can be no assurance that a court or jury would agree with the Utility.  The Utility believes that it is probable that it will incur a loss of at least $750 million for all potential damages described above.  This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and other damages that the Utility could be liable for under the theories of inverse condemnation and/or negligence. 

For additional information, see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

Other Enforcement Matters

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 electric and natural gas safety regulations, prohibited ex parte communications between the Utility and CPUC personnel, and other enforcement matters.   See “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

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Diablo Canyon Nuclear 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.

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 was that the Central Coast Board renew Diablo Canyon's permit.

However,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 to develop additional information on possible mitigation measures for Central Coast Board staff.In2005, the Central Coast Board reviewedthe scientists' draft report recommending several such mitigation measures, but no action was taken.

Subsequently, the California State Water Resources Control Board adopted a Once-Through Cooling Water Policy in May 2010 which requires Diablo Canyon to be in compliance with the policy by December 2024 and allows for alternative compliance measures at nuclear power plants.

On June 20, 2016, the Utility entered into a joint proposal with certain parties to retire Diablo Canyon at the expiration of its current operating licenses in 2024 and 2025 and replace it with a GHG-free portfolio of energy efficiency, renewables and energy storage. The Utility expects that the State Board’s OTC Policy and its decision to retire Diablo Canyon will affect the terms of a final settlement agreement between the Utility, the Central Coast Water Board and the California Attorney General’s Office. Also, as required under the State Board’s OTC Policy, beginning in 2017, the Utility will pay an annual interim mitigation fee until operations cease at the end of the current licenses.

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 must be 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 a civil 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.In January 2017, the Utility and the district attorney reached an agreement on a stipulated judgement that resolves the matter.The stipulated judgment includes a fine of approximately $175,000. In addition, a $75,000 fine will be held in abeyance for 5 years, and would be payable to the San Benito County district attorney in case of non-compliance with certain remedial requirements of the stipulated judgment. The stipulated judgment was executed by the court on January 27, 2017.

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Transformer Oil Release in Sonoma County

During a rain storm in February 2015, transformer oil was released into an underground vault in the City of Santa Rosa, in Sonoma County, while a Utility crew was replacing a broken transformer.  Following further rains, the oil released from the vault and reached a nearby creek.  The event was investigated by Santa Rosa Fire Department, the local environmental enforcement authority, and later referred to the Sonoma County District Attorney’s Office.  In May 2016, the District Attorney informed the Utility that it would seek penalties and costs in excess of $100,000 for alleged violations of several sections of the California Health and Safety and California Government codes which prohibit unauthorized spills or releases of oil into waters of the state and require that releases be reported to the Office of Emergency Services.  In November 2016, the Utility and the Sonoma County district attorney reached an agreement on a stipulated judgment that resolves the matter.  The stipulated judgment includes a fine of $80,000, reimbursement of enforcement costs of $40,000, and injunctive provisions requiring improvements to the Utility’s vault dewatering procedure and training.  In November 2016, the court approved the stipulated judgment. 

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

EXECUTIVE OFFICERS OF THE REGISTRANTS

The following individuals serve as executive officers ⁽¹⁾ of PG&E Corporation and/or the Utility, as of February 16, 2017.  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. (2)	67	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(2)	58	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
Geisha J. Williams (2)	55	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
Jason P. Wells	39	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
John R. Simon	52	Executive Vice President, Corporate Services and Human Resources, PG&E Corporation	August 17, 2015 to present
		Senior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric Company	April 16, 2007 to August 16, 2015
Karen A. Austin	55	Senior Vice President and Chief Information Officer	June 1, 2011 to present
		President, Consumer Electronics, Sears Holdings	February 2009 to May 2011

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Desmond A. Bell (3)	54	Senior Vice President, Safety and Shared Services	January 1, 2012 to present
Helen A. Burt (3)	60	Senior Vice President, External Affairs and Public Policy, PG&E Corporation and Pacific Gas and Electric Company	September 30, 2015 to present
		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	49	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	55	Senior Vice President, Generation and Chief Nuclear Officer	March 28, 2016 to present
		Senior Vice President, Power Generation and Chief Nuclear Officer	September 8, 2015 to March 27, 2016
		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
Patrick M. Hogan	53	Senior Vice President, Electric Operations	February 1, 2017 to present
		Senior Vice President, Electric Transmission and Distribution	March 1, 2016 to January 31, 2017
		Vice President, Electric Strategy and Asset Management	September 8, 2015 to February 29, 2016
		Vice President, Electric Operations, Asset Management	November 18, 2013 to September 7, 2015
		Senior Vice President, Transmission and Distribution Engineering and Design, BC Hydro	October 2011 to November 2013
Julie M. Kane	58	Senior Vice President and Chief Ethics and Compliance Officer, PG&E Corporation and Pacific Gas and Electric Company	May 18, 2015 to present
		Vice President, General Counsel 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, 2015
Steven E. Malnight	44	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
Dinyar B. Mistry	55	Senior Vice President, Human Resources and Chief Diversity Officer, PG&E Corporation and Pacific Gas and Electric Company	February 1, 2017 to present

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		Senior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric Company	June 1, 2016 to January 31, 2017
		Senior Vice President, Human Resources, Chief Financial Officer, and Controller	March 1, 2016 to May 31, 2016
		Senior Vice President, Human Resources and Controller, PG&E Corporation	March 1, 2016 to May 31, 2016
		Vice President, Chief Financial Officer, and Controller	October 1, 2011 to February 28, 2016
		Vice President and Controller, PG&E Corporation	March 8, 2010 to February 28, 2016
Hyun Park (4)	55	Senior Vice President and General Counsel, PG&E Corporation	November13, 2006 to present
Jesus Soto, Jr.	49	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	55	Senior Vice President, Energy Policy and Procurement	September 8, 2015 to present
		Senior Vice President, Energy Procurement	October 1, 2008 to September 8, 2015
David S. Thomason	41	Vice President, Chief Financial Officer, and Controller	June 1, 2016 to present
		Vice President and Controller, PG&E Corporation	June 1, 2016 to present
		Senior Director, Financial Forecasting and Analysis	March 2, 2015 to May 31, 2016
		Senior Director, Corporate Accounting	March 2, 2014 to March 1, 2015
		Senior Director, Financial Forecasting and Analysis	September 1, 2012 to March 1, 2014
		Director, Planning, Forecasting and Reporting	October 3, 2011 to August 31, 2012

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

(2)On November 14, 2016, the Board of Directors of PG&E Corporation elected Mr. Earley to the role of Executive Chair of the Board of PG&E Corporation and Ms. Williams to the role of Chief Executive Officer and President of PG&E Corporation, both effective March 1, 2017.  Also on November 14, 2016, the Board of Directors of the Utility elected Mr. Stavropoulos as President and Chief Operating Officer of the Utility effective March 1, 2017.

(3) Mr. Bell and Ms. Burt will step down from their positions effective March 1, 2017.

(4) Mr. Park will step down from his position effective March 1, 2017 but is expected to remain with PG&E Corporation until September 1, 2017.

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PART II

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

As of February 7, 2017, there were 56,835 holders of record of PG&E Corporation common stock.  PG&E Corporation common stock is listed on the New York Stock Exchange and is traded under the symbol “PCG”.  The high and low closing 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 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 $95 million during the quarter ended December 31, 2016.  PG&E Corporation did not make any sales of unregistered equity securities during 2016in reliance on an exemption from registration under the Securities Act of 1933, as amended. 

Issuer Purchases of Equity Securities

During the quarter ended December 31, 2016, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding.  PG&E Corporation does not have any preferred stock outstanding.  Also, during the quarter ended December 31, 2016, 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)	2016		2015		2014		2013		2012
PG&E Corporation
For the Year
Operating revenues	$	17,666	$	16,833	$	17,090	$	15,598	$	15,040
Operating income		2,177		1,508		2,450		1,762		1,693
Net income		1,407		888		1,450		828		830
Net earnings per common share, basic (1)		2.79		1.81		3.07		1.83		1.92
Net earnings per common share, diluted		2.78		1.79		3.06		1.83		1.92
Dividends declared per common share (2)		1.93		1.82		1.82		1.82		1.82
At Year-End
Common stock price per share	$	60.77	$	53.19	$	53.24	$	40.28	$	40.18
Total assets (3)		68,598		63,234		60,228		55,693		52,530
Long-term debt (excluding current portion) (3)		16,220		15,925		15,151		12,805		12,598
Capital lease obligations (excluding current
portion)(4)		31		49		69		90		113
Pacific Gas and Electric Company
For the Year
Operating revenues	$	17,667	$	16,833	$	17,088	$	15,593	$	15,035
Operating income		2,181		1,511		2,452		1,790		1,695
Income available for common stock		1,388		848		1,419		852		797
At Year-End
Total assets (5)		68,374		63,037		59,964		55,137		52,003
Long-term debt (excluding current portion) (5)		15,872		15,577		14,799		12,805		12,247
Capital lease obligations (excluding current
portion)(4)		31		49		69		90		113

(1) See “Overview – 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) In accordance with ASU No. 2015-03, PG&E Corporation restated $105 million in 2015, $101 million in 2014, $88 million in 2013, and $81 million in 2012, of debt issuance costs.  Total assets and total liabilities were each reduced by the amounts above with no impact to net income or total shareholders’ equity previously reported.

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

(5) In accordance with ASU No. 2015-03, the Utility restated $103 million in 2015, $99 million in 2014, $88 million in 2013, and $80 million in 2012, of debt issuance costs.  Total assets and total liabilities were each reduced by the amounts above with no impact to net income or total shareholders’ equity previously reported.

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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 serving 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 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, 2016 compared to the year ended December 31, 2015 (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 (1)		(diluted)
Income Available for Common Shareholders - 2015	$	874	$	1.79
Add items impacting comparability:
Fines and penalties		578		1.19
Pipeline-related expenses		61		0.13
Legal and regulatory related expenses		35		0.07
Natural gas matters insurance recoveries		(29)		(0.06)
Earnings from Operations - 2015 (2)	$	1,519	$	3.12
2015 GT&S revenue (3)		300		0.60
Growth in rate base earnings		102		0.20
Regulatory and legal matters		1		-
Gain on disposition of SolarCity stock (4)		(14)		(0.03)
Increase in shares outstanding		-		(0.09)
Miscellaneous		(24)		(0.04)
Earnings from Operations - 2016 (2)	$	1,884	$	3.76
Less items impacting comparability:
Butte fire related costs (net of insurance) (5)		(137)		(0.27)
Fines and penalties (6)		(307)		(0.61)
Pipeline-related expenses (7)		(67)		(0.13)
Legal and regulatory related expenses (8)		(43)		(0.09)
GT&S capital disallowance(9)		(130)		(0.26)
GT&S revenue(10)		193		0.38
Income Available for Common Shareholders - 2016	$	1,393	$	2.78

(1)  All amounts presented in the table above are tax-adjusted at PG&E Corporation’s tax rate of 40.75% except for fines, which are not tax deductible. See footnote (6) below.

(2)  “Earnings from operations” is not calculated in accordance with GAAP and excludes the items impacting comparability shown in footnotes (5) through (10).

(3)Represents the increase in 2016 revenues authorized December 1, 2016 in the final phase two decision of the Utility’s 2015 GT&S rate case.

(4)Represents the gain recognized during the year ended December 31, 2015. No comparable gain was recognized in 2016.

(5)The Utility recorded costs of $232 million (before the tax impact of $95 million) during the year ended December31, 2016 associated with the Butte fire, net of insurance.  This includes accrued charges of $750 million (before the tax impact of $306 million)related to estimated third-party claims in connection with the Butte fire, partially offset by $625 million (before the tax impact of $255 million) as probable of insurance recovery.  The Utility also incurred charges of $107 million (before the tax impact of $44 million) for Utility clean-up, repair, and legal costs associated with the Butte fire. 

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(6)The Utility incurred costs of $498 million (before the tax impact of $191 million), during the year ended December31, 2016 associated with fines and penalties.This includes costs of $412 million (before the tax impact of $168 million) associated with safety-related cost disallowances imposed by the CPUC in its April 9, 2015 decision in the gas transmission pipeline investigations.The Utility also recorded $57 million (before the tax impact of $23 million) for disallowances imposed by the CPUC in its final phase two decision of the 2015 GT&S rate case for prohibited ex parte communications.  In addition, the Utility accrued fines of $26 million in connection with the final decision approved by the CPUC on August 18, 2016 in its investigation regarding natural gas distribution record-keeping practices and $3 million in connection with the maximum statutory fine imposed on January 26, 2017 in the federal criminal trial against the Utility.  These fines are not tax deductible.Future fines or penalties may be imposed in connection with other enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications. 

(7) The Utility incurred costs of $113million (before the tax impact of $46 million), during theyear ended December31, 2016 for pipeline related expenses incurred in connection with the multi-year effort to identify and remove encroachments from transmission pipeline rights of way.

(8)The Utility incurred costs of $72 million (before the tax impact of $29 million), during theyear ended December31, 2016 for legal and regulatory related expenses incurred in connection with various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

(9) The Utility incurred charges of $219million (before the tax impact of $89 million), during the year ended December31, 2016, for disallowed capital expenditures based on the CPUC final phase one decision dated June 23, 2016 in the 2015 GT&S rate case, including $134 million (before the tax impact of $54 million)for the disallowed portion of the 2011 through 2014 capital expenditures in excess of adopted amounts and $85 million (before the tax impact of $35 million) for the Utility’s estimate of 2015 through 2018 capital expenditures that are likely to exceed authorized amounts.(See “Regulatory Matters” below for more information.)

(10)As a result of the timing of the CPUC’s final phase two decision in the 2015 GT&S rate case, the Utility recorded $325 million (before the tax impact of $132 million) in excess of the 2016 authorized revenue requirement during the twelve months ended December 31, 2016.

Key Factors Affecting Financial Results

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, Litigation, and Regulatory Matters.  The Utility’s future financial results may continue to be impacted by the outcome of current and future enforcement, litigation, and regulatory matters, including the Butte fire litigation, potential costs associated with the alleged violations of the CPUC’s ex parte communication rules, the cost of complying with the terms of probation and monitorship imposed in the sentencing phase of the federal criminal trial and related remedial and other measures, and potential penalties in connection with the Utility’s self-report related to its customer service representatives' drug and alcohol testing program.  (See “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

● The Timing and Outcome of Ratemaking Proceedings.  The Utility’s results may be impacted by the timing and outcome of its 2017 GRC, FERC TO rate case, and petition for modification related to its cost of capital.  Based on the current schedule, the Utility expects a final decision in its 2017 GRC in the first half of 2017. (See “Regulatory Matters − 2017 General Rate Case” below for more information.)In addition, settlement negotiations are ongoing related tothe Utility’s FERC TO rate case requesting a 2017 retail electric transmission revenue requirement.  (See “Regulatory Matters−FERC Transmission Owner Rate Cases” below for more information.)  Also, on February 7, 2017, the Utility filed with the CPUC a petition for modification related to its cost of capital.  (See “Regulatory Matters – CPUC Cost of Capital” below for more information.) The outcome of regulatory proceedings can be affected by many factors, including arguments made by intervening parties, potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors.  

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 ●  The Ability of the Utility to Control and Recover Operating Costs and Capital Expenditures.  The Utility is committed to delivering safe, reliable, sustainable, and affordable electric and gas services to its customers.  Increasing demands from state laws and policies relating to increased renewable energy resources, the reduction of GHG emissions, the expansion of energy efficiency programs, the development and widespread deployment of distributed generation and self-generation resources, and the development of energy storage technologies have increased pressure on the Utility to achieve efficiencies in its operations in order to maintain the affordability of its service.  In any given year the Utility’s ability to earn its authorized rate of return depends on its ability to manage costs within the amounts authorized in rate case decisions.The Utility forecasts that in 2017 it will incur unrecovered pipeline-related expenses ranging from $80 million to $125 million which primarily relate to costs to identify and remove encroachments from transmission pipeline rights-of-way.  Also, the CPUC decision in the Utility’s 2015 GT&S rate case establishes various cost caps that will increase the risk of overspend over the rate case cycle. (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

●   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 2016, PG&E Corporation issued $842 million of common stock and used $835 million of the cash proceeds to make equity contributions to the Utility.  PG&E Corporation forecasts that it will continue issuing a material amount of equity in future years, including $400 million to $600 million in 2017, primarily to support the Utility’s capital expenditures.  PG&E Corporation may issue additional equity 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 could 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,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 2016Form 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 2016 Form 10-K.  See the section entitled “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 and 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 for 2016, 2015, and 2014.  See “Key Factors Affecting Financial Results” 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 available for common shareholders:

(in millions)	2016		2015		2014
Consolidated Total	$	1,393	$	874	$	1,436
PG&E Corporation		5		26		17
Utility	$	1,388	$	848	$	1,419

PG&E Corporation’s net income consists primarily ofincome taxes, interest expense on long-term debt, and other income from investments.  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, with no corresponding gains in 2016.

Utility

The table below shows certain items from the Utility’s Consolidated Statements of Income for 2016, 2015,and 2014.  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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	2016						2015						2014
	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	$	7,955	$	5,910	$	13,865	$	7,442	$	6,215	$	13,657	$	7,059	$	6,597	$	13,656
Natural gas operating revenues		2,767		1,035		3,802		2,082		1,094		3,176		2,072		1,360		3,432
Total operating revenues		10,722		6,945		17,667		9,524		7,309		16,833		9,131		7,957		17,088
Cost of electricity		-		4,765		4,765		-		5,099		5,099		-		5,615		5,615
Cost of natural gas		-		615		615		-		663		663		-		954		954
Operating and maintenance		5,787		1,565		7,352		5,402		1,547		6,949		4,247		1,388		5,635
Depreciation, amortization, and decommissioning		2,754		-		2,754		2,611		-		2,611		2,432		-		2,432
Total operating expenses		8,541		6,945		15,486		8,013		7,309		15,322		6,679		7,957		14,636
Operating income		2,181		-		2,181		1,511		-		1,511		2,452		-		2,452
Interest income (1)						22						8						8
Interest expense(1)						(819)						(763)						(720)
Other income, net (1)						88						87						77
Income before income taxes						1,472						843						1,817
Income tax provision (benefit)(1)						70						(19)						384
Net income						1,402						862						1,433
Preferred stock dividend requirement (1)						14						14						14
Income Available for Common Stock					$	1,388					$	848					$	1,419

(1) These items impacted earnings.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for 2016, 2015, and 2014, focusing on revenues and expenses that impacted earnings for these periods.

Operating Revenues

The Utility’s electric and natural gas operating revenues that impacted earnings increased $1.2 billion or 13% in 2016 compared to 2015, primarily as a result of approximately $700million ofincremental revenues authorized in the 2015 GT&S rate case and approximately $425 million of additional base revenues as authorized by the CPUC in the 2014 GRC decision and by the FERC in the TO rate case.

The Utility included the authorized increase for the 2015 GT&S rate case period in rates starting August 1, 2016. The Utility will collect, over a 36-month period, the difference between adopted revenue requirements and amounts previously collected in rates, retroactive to January 1, 2015.  Accounting rules allow the Utility to recognize revenues in a given year only if they will be collected from customers within 24 months of the end of that year.  As a result, the Utility will recognize the remaining $102 million in the first quarter of 2017. (See “Regulatory Matters” below.)

The Utility’s electric and natural gas operating revenues that impacted earnings increased $393 million or 4% in 2015 compared to 2014, primarily as 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.

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Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings increased $385 million or 7% in 2016 compared to 2015, primarily due to $857 million in charges for third-party claims, Utility clean-up, repair, and legal costs related to the Butte fire, $219 million in permanently disallowed capital spending (see “Regulatory Matters” below), $34 million in charges recorded in connection with the final CPUC decision related to the natural gas distribution facilities record-keeping investigation, the federal criminal trial, and the atmospheric corrosion inspection self-report, $24 million in higher pipeline-related expenses and legal and regulatory related expenses during the year ended December 31, 2016, an escalation related to labor, benefits, and service contracts, and accelerated transmission and distribution project work.  These increases were partially offset by $500 million in charges associated with the Penalty Decision for customer refunds and fines incurred in 2015 with no corresponding charges in 2016 and approximately $125 million in lower disallowed capital charges associated with the Penalty Decision in 2016.  Additionally, the Utility recorded approximately $625 million in probable insurance recoveries related to the Butte fire in the year ended December 31, 2016 as compared to $49 million of insurance recoveries for third-party claims related to the San Bruno accident for the same period in 2015.  (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8.) 

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” in Note 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 recoveries for 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.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses increased $143 million or 5% in 2016 compared to 2015 and $179 million or 7% in 2015 compared to 2014.  In 2016, the increase was primarily due to the impact of capital additions.  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.

Interest Expense

The Utility’s interest expenses increased by $56 million or 7% in the year ended December 31, 2016 compared to the same period in 2015, primarily due to the issuance of additional long-term debt.  The Utility’s interest expenses increased by $43 million or 6% in the year ended December 31, 2015 compared to the same period in 2014, primarily due to the issuance of long-term debt.

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 income tax provision increased $89million, or 468%, in 2016as compared to 2015.  The increase in the tax provision was primarily the result of the statutory tax effect ofhigher pre-tax income in 2016 compared to 2015, partially offset by higher tax benefits from property-related timing differences in 2016 compared to 2015.  The higher effective tax rate is driven by higher pre-tax earnings in 2016, partially offset by rate impact from property-related timing differences.

The Utility’s income tax provisiondecreased $403million, or105%,in2015as compared to2014. This is primarily the result of the statutory tax effect oflower pre-tax income and higher tax benefits from property-related timing differences in 2015 as compared to 2014. The lower effective tax rate in 2015 is the result of lower pre-tax earnings in 2015 and rate impact from property-related timing differences.

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

	2016		2015		2014
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)	(2.2)		(4.8)		1.6
Effect of regulatory treatment of fixed asset differences (2)	(23.4)		(33.7)		(14.7)
Tax credits	(0.8)		(1.3)		(0.7)
Benefit of loss carryback	(1.1)		(1.5)		(0.8)
Non-deductible penalties (3)	0.8		4.3		0.3
Other, net(4)	(3.5)		(0.2)		0.4
Effective tax rate	4.8	%	(2.2)	%	21.1	%

(1)Includes the effect of state flow-through ratemaking treatment.  In 2016 and 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 costsas authorized by the 2014 GRC decision in all periods presented and by the 2015 GT&S decision which impacted only 2016.  All amounts are impacted by the level of income before income taxes.  The 2014 GRC and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.  

(3)Primarily represents the effects of non-tax deductible fines and penalties associated with the natural gas distribution facilities record-keeping decision for the year ended December 31, 2016 and the effects of the Penalty Decision for the year ended December 31, 2015.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.

(4)In 2016, the amount primarily represents the impact of tax audit settlements.

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 9 of the Notes to the Consolidated Financial Statements in Item 8.) 

(in millions)	2016		2015		2014
Cost of purchased power	$	4,510	$	4,805	$	5,266
Fuel used in own generation facilities		255		294		349
Total cost of electricity	$	4,765	$	5,099	$	5,615
Average cost of purchased power per kWh(1)	$	0.109	$	0.100	$	0.101
Total purchased power (in millions of kWh) (2)		41,324		48,175		52,008

(1) Cost of purchased power was impacted primarily by a higher percentage of renewable energy resources.

(2)The decrease in purchased power primarily resulted from an increase in generation from the Utility’s Diablo Canyon nuclear power plant and its hydroelectric facilities as well as lower electric customer demand. 

The Utility’s total purchased power is driven by customer demand, the availability of the Utility’s own generation facilities (including Diablo Canyon and its 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 and 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)	2016		2015		2014
Cost of natural gas sold	$	481	$	518	$	813
Transportation cost of natural gas sold		134		145		141
Total cost of natural gas	$	615	$	663	$	954
Average cost per Mcf of natural gas sold	$	2.45	$	2.74	$	4.37
Total natural gas sold (in millions of Mcf)		196		189		186

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 2016, 2015, and 2014, 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 to recover its cost of capital.  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 structureconsisting 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 issuances and repayments under its revolving credit facility and commercial paper program.  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 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 Notes 9 and 13 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 $400 million and $600 million in common stock during 2017, primarily to fund equity contributions to the Utility.  The Utility’s equity needs will continue to be affected by the timing and outcome of unrecoverablepipeline-related expenses and by fines, penalties and claims 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 could have a material dilutive impact on PG&E Corporation’s EPS.

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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.  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, prior to October 2016, primarily consisted 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.  In October 2016, the Utility received approval from the bankruptcy court to release the remaining $161 million of cash held in escrow to unrestricted cash for use by the Utility.  (See “Resolution of Remaining Chapter 11 Disputed Claims” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

Financial Resources

Debt and Equity Financings

The Utility issued $1.0 billion in long-term debt and $500 million in short-term debt during the year ended December 31, 2016.  (See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.)

During 2016, PG&E Corporation sold 2.6million sharesof its common stock under the February 2015 equity distribution agreement for cash proceeds of $149 million, net of commissions paid of $1.3million.  As of December 31, 2016, the remaining gross sales available under this agreement were $275 million.

In August 2016, PG&E Corporation sold 4.9 million shares of its common stock in an underwritten public offering for net cash proceeds of $309 million.

In addition,during 2016, PG&E Corporation sold 7.4 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 $364 million.

The proceeds from equity issuances were used for general corporate purposes, including the contribution of equity to the Utility.  For the year ended December 31, 2016, PG&E Corporation made equity contributions to the Utility of $835 million.  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 2017.

Revolving Credit Facilities and Commercial Paper Programs

In June 2016, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2020 to April 27, 2021. At December 31, 2016, 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.)

PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and $2.5 billion, respectively.  For the year ended December 31, 2016, PG&E Corporation and the Utility had an average outstanding commercial paper balance of $84 million and $837 million, and a maximum outstanding balance of $176 million and $1.4 billion, respectively. At December 31, 2016, the Utility had an outstanding commercial paper balance of $1.0 billion and PG&E Corporation did not have any commercial paper outstanding.  (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, 2016, 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 common stock and at least 70% of the 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, 2016, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

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Dividends

In May 2016, the Board of Directors of PG&E Corporation and the Utility each adopted a new target dividend payout ratio range of 55% to 65% of earnings, with a target to reach a payout ratio of approximately 60% by 2019. Each Board of Directors retains authority to change the respective common stock dividend policy and dividend payout ratio at any time, especially if unexpected events occur that would change its view as to the prudent level of cash conservation. No dividend is payable unless and until declared by the applicable Board of Directors.

PG&E Corporation

For the first quarter of 2016, the Board of Directors of PG&E Corporation declared a common stock dividend of $0.455 per share.  In May 2016, the Board of Directors of PG&E Corporation declared a new quarterly common stock dividend of $0.49 per share.  As a result, for each of the second, third and fourth quarters of 2016, the Board of Directors of PG&E Corporation declared a common stock dividend of $0.49 per share.  In 2016, total dividends were $1.925 per share.  For each of the quarters in2015 and 2014, 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 shareholders by PG&E Corporation were $921 million in 2016, $856 million in 2015, and $828 million in 2014.  In December 2016, the Board of Directors of PG&E Corporation declared quarterly dividends of $0.49 per share, totaling $248million, of which approximately $243 million was paid on January 15, 2017 to shareholders of record on December 30, 2016.

Utility

For the first quarter of 2016, the Board of Directors of the Utility declared a common stock dividend of $179 million to PG&E Corporation.  For each of the second, third and fourth quarters of 2016, the Board of Directors of the Utility declared common stock dividends of $244 million to PG&E Corporation.  In 2016, total dividends paid by the Utility to PG&E Corporation were $911 million.  For each of the quarters in 2015 and 2014, the Board of Directors of the Utility declared common stock dividends of $179 million to PG&E Corporation for annual dividends paid of $716million in 2015 and 2014.In addition, the Utility paid $14 million of dividends on preferred stock in each of 2016, 2015, and 2014.  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 2016, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on February 15, 2017, to shareholders of record on January 31, 2017.

Utility Cash Flows

The Utility’s cash flows were as follows:

	Year Ended December 31,
(in millions)	2016		2015		2014
Net cash provided by operating activities	$	4,344	$	3,747	$	3,632
Net cash used in investing activities		(5,526)		(5,211)		(4,799)
Net cash provided by financing activities		1,194		1,468		1,157
Net change in cash and cash equivalents	$	12	$	4	$	(10)

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 2016, net cash provided by operating activities increased by $597 million compared to 2015.  This increase was partially due to the Utility receiving an additional $170 million in tax refunds in 2016 than in 2015.  The remaining increase was primarily due to fluctuations in activities within the normal course of business such as timing and amount of customer billings and vendor billings and payments. During 2015, net cash provided by operating activities increased by $115 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.

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

• the timing and outcome of ratemaking proceedings, including the 2017 GRC and the TO rate case, and cost of capital proceeding;

• the timing and amounts of costs that may be incurred in connection with claims associated with Butte fire and the timing and amount of related insurance recoveries, fines or penalties that may be imposed in connection with the ex parte OII or costs in connection with a potential settlement, fines or penalties that may be imposed in connection with other enforcement and litigation matters, costs associated with the terms of probation and monitorship imposed in the sentencing phase of the federal criminal trial, and potential remedial and other measures that could be imposed on the Utility in connection with the DOI debarment proceeding (see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8 below);

• the timing and amount of costs the Utility incurs, but does not recover, associated with its natural gas system;

• the timing and amount of tax payments (including the bonus depreciation), tax refunds, net collateral payments, and interest payments, as well as changes in tax regulations that could be adopted by Congress as a result of the new federal administration and other proposals; and

• 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 $315 million during 2016 as compared to 2015 primarily due to an increase of approximately $440 million in capital expenditures, partially offset by an increase in restricted cash released from escrow by approximately $160 million.  (See “Resolution of Remaining Chapter 11 Disputed Claims” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)  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.

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 approximately $6.0 billion in capital expenditures in each of the years 2017, 2018, and 2019.

Financing Activities

During 2016, net cash provided by financing activities decreased by$274 million as compared to 2015.  During 2015, net cash provided by financing activities increased by $311 million as compared to 2014.  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, 2016:

	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):	$	1,495	$	2,408	$	3,328	$	22,452	$	29,683
Purchase obligations (2):
Power purchase agreements:		3,417		6,175		5,844		29,506		44,942
Natural gas supply, transportation, and storage		536		329		241		455		1,561
Nuclear fuel agreements		97		188		179		136		600
Pension and other benefits (3)		388		776		776		388		2,328
Operating leases (2)		44		80		75		168		367
Preferred dividends (4)		14		28		28		-		70
PG&E Corporation
Long-term debt (1):		8		362		-		-		370
Total Contractual Commitments	$	5,999	$	10,346	$	10,471	$	53,105	$	79,921

(1)Includes interest payments over the terms of the debt.  Interest is calculated using the applicable interest rate at December 31, 2016 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. 

Butte Fire Litigation

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California.  On April 28, 2016, Cal Firereleased its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures.  Cal Fire’sreport concluded that the wildfire was caused when a Gray Pine tree contactedthe Utility’selectric line which ignited portions of the tree, and determined that the failure by the Utilityand/or its vegetation management contractors, ACRT Inc. and Trees, Inc.,to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. In a press release also issued on April 28, 2016, Cal Fire indicated that it will seek to recover firefighting costs in excess of $90 million from the Utility.

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On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California for Sacramento County. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council had previously authorized the coordination of all cases in Sacramento County. As of December 31, 2016, complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 1,950 individual plaintiffs representing approximately 950 households and their insurance companies. These complaints are part of or are in the process of being added to the two master complaints.Plaintiffs seek to recover damages and other costs, principally based on inverse condemnation and negligence theories of liability.  The number of individual complaints and plaintiffs may increase in the future. 

The Utility continues mediating and settling cases.  The next case management conference is scheduled for March 2, 2017.

In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees without having been found negligent, through the theory of inverse condemnation.  In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent.  The Utility believes it was not negligent; however, there can be no assurance that a court or jury would agree with the Utility.  The Utility believes that it is probable that it will incur a loss of at least $750 million for all potential damages described above.  This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and other damages that the Utility could be liable for under the theories of inverse condemnation and/or negligence.

The Utility believes that it is reasonably possible that it will incur losses related to Butte fire claims in excess of $750 million accrued through December 31, 2016 but is currently unable to reasonably estimate the upper end of the range of losses because it is still in an early stage of the evaluation of claims, the mediation and settlement process, and discovery.  The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors.  As more information becomes known, including additional discovery from the plaintiffs and results from the ongoing mediation and settlement process, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued. 

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of approximately $900 million.  Such insurance coverage is subject to the terms and limitations of the applicable policies and may not be sufficient to cover the Utility’s ultimate liability.

The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range.  The Utility has recorded $625 million for probable insurance recoveries in connection with losses related to the Butte fire.  While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.  In addition, the Utility is pursuing coverage under the insurance policies of its two vegetation management contractors, including under policies where the Utility is listed as an additional insured.  Recoveries of any amounts under these policies are uncertain.  If the ultimate liability exceeds the amounts recovered through insurance, the Utility would expect to seek authorization from the CPUC and the FERC to recover any excess amounts from customers. The Utility is unable to predict the timing or outcome of any such proceeding, or the timing of recovery from customers, if any.  The resolution of claims, any future regulatory proceeding, and the recoveries from other potentially responsible parties and customers could extend over a number of years. (For more information, see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

Department of Interior Inquiry

In September 2015, the Utility was notified that the DOI had initiated an inquiry into whether the Utility should be suspended or debarred from entering into federal procurement and non-procurement contracts and programs citing the San Bruno explosion and indicating, as the basis for the inquiry, alleged poor record-keeping, poor identification and evaluation of threats to gas lines and obstruction of the NTSB’s investigation.  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.  On April 8, 2016, the Utility received a series of follow-up questions from the DOI regarding its November 2015 submission.   On November 21, 2016, the Utility provided the DOI with a supplemental submission in which it addressed the DOI’s April 8, 2016 questions.   The Utility continues to fully cooperate with the DOI.

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As a result of the August 9, 2016 jury’s verdict in the federal criminal trial, the Utility updated its registration on the federal government’s System for Award Management (SAM), a federal procurement database, to reflect the verdict.  Under federal law, the government may not enter into a contract with any corporation that was convicted of a felony criminal violation under any federal law within the preceding 24 months, where the awarding agency is aware of the conviction, unless an agency has considered suspension or debarment of the corporation and made a determination that this action is not necessary to protect the interests of the government. 

On December 21, 2016, the Utility and the DOI entered into an interim administrative agreement that reflects the DOI’s determination that the Utility remains eligible to contract with federal government agencies while the DOI determines whether any further action is necessary to protect federal government’s business interests.  The agreement will be effective until superseded by an amended agreement or determination.  The agreement also provides that the DOI is still conducting a review to determine whether the Utility has an effective compliance and ethics program and that the DOI is required to use its best efforts to complete its review before the end of 2017.  If the DOI determines that the Utility’s program is not generally effective in preventing and detecting criminal conduct, the Utility may be required to enter into an amended administrative agreement and implement remedial and other measures, such as a requirement that the Utility’s natural gas operations and/or compliance and ethics programs be supervised by one or more independent third party monitor(s).

The Utility could incur material costs, not recoverable through rates, to implement remedial and other measures that could be imposed, the amount of which the Utility is currently unable to estimate.

Litigation Related to the San Bruno Accident and Natural Gas Spending

As of December 31, 2016, there were seven 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 theSan Bruno Fire Derivative Casesand are pending in the Superior Court of California, County of San Mateo.The remaining three cases are Tellardin v. Anthony F. Earley, Jr.,. et al.,Iron Workers Mid-South Pension Fund v. Johns, et al., and Bushkin v. Rambo et al.

On December 8, 2015, the California Court of Appeal issued a writ of mandate to the Superior Court of California, San Mateo County, ordering the court to stay all proceedings in the four consolidated San Bruno Fire Derivative Cases pending conclusion of the federal criminal proceedings against the Utility. On November 16, 2016, counsel in the four consolidated San Bruno Fire Derivative cases, as well as counsel in the Tellardin action, appeared for a status conference in the San Mateo Superior Court. The court reaffirmed that all proceedings in these actions were stayed until the conclusion of the Utility’s federal criminal proceeding, at which point they were directed to meet and confer and report back to the court.  The parties completed a mediation session on December 8-9, 2016 and continue discussions about the potential resolution of the matter.  These actions remain stayed.

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Bushkin v. Rambo et al., pending in the United States District Court for the Northern District of California, has been designated by the plaintiff as related to the pending shareholder derivative suit Iron Workers Mid-South Pension Fund v. Johns, et al., discussed below. The plaintiff in the Bushkin lawsuit has agreed that this case should be stayed pending conclusion of the federal criminal trial against the Utility and, on May 3, 2016, the judge entered a stipulated order staying the case. The order also provides that the parties should meet and confer within 30 days after the criminal trial concludes and provide the court a status update. Despite the stay of his complaint, on June 20, 2016 the Bushkin plaintiff filed a petition in the Superior Court of California, San Francisco County, seeking to enforce the plaintiff’s claimed right as a shareholder to inspect certain PG&E Corporation accounting books and records pursuant to section 1601 of the California Corporations Code. On July 25, 2016, PG&E Corporation filed a motion to stay plaintiff’s petition until the appellate stay of the San Bruno Fire Derivative Cases has been lifted, or, in the alternative, a demurrer asking the court to dismiss plaintiff’s petition. On August 29, 2016, the San Francisco Superior Court granted PG&E Corporation’s motion, and indicated that plaintiff’s petition was stayed pending resolution of the criminal matter against the Utility.  On January 13, 2017, the parties submitted a joint case management statement advising the court that, because the Utility had not yet been sentenced, the case should remain stayed until at least March 10, 2017, when the parties will advise the court of further developments.  While the Utility was sentenced in the federal criminal proceeding on January 26, 2017, this matter remains stayed until at least March 10, 2017.

The Iron Workers action pending in the United States District Court for the Northern District of California has been stayed pending the resolution of the San Bruno Fire Derivative Cases. On May 5, 2016, the court ordered the parties to meet and confer within 30 days after the criminal trial concludes and provide the court a status update. At the court’s request, on August 22, 2016, the parties filed a statement requesting that the case continue to be stayed until resolution of the San Bruno Fire Derivative Cases. On August 31, 2016, the court set a case management conference for September 30, 2016, and requested the parties to file a joint case management conference statement by September 23, 2016. On September 30, 2016, the court decided to continue the stay pending the resolution of the federal criminal proceeding against the Utility and ordered the parties to submit a joint status report on or before March 15, 2017.  This matter remains stayed until at least March 15, 2017.

For more information about the federal criminal proceeding, see Note 13 of the Notes to the Consolidated Financial Statements and Item 3 Legal Proceedings.

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

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REGULATORY MATTERS

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

2017 General Rate Case

On September 1, 2015, the Utility filed its 2017 GRC application with the CPUC.  On August 3, 2016, the Utility, together with ORA, TURN, and 12 other intervening parties filed a motion with the CPUC seeking approval of a settlement agreement that resolves nearly all of the issues raised by the parties in the Utility’s 2017 GRC.  All parties who filed testimony in the case joined the settlement agreement, which was the subject of a one-day workshop overseen by the assigned commissioner and ALJ.  The settlement agreement will ultimately be considered by the full commission.  In the GRC proceeding, the CPUC will determine the annual amount of base revenues (or “revenue requirements”) that the Utility will be authorized to collect from customers from 2017 through 2019 or 2020 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.)

Revenue Requirements and Attrition Year Revenues

The settlement agreement proposed that the Utility’s 2016 authorized revenue requirement of $7.9 billion be increased by $88 million, effective January 1, 2017.  The settlement agreement further proposed an increase to the authorized 2017 revenues of $444 million in 2018 and an additional increase of $361 million in 2019, as shown in the table below.

The settlement agreement identified two contested issues.  First, the parties were unable to agree on whether there should be a third post-test year or “attrition” year for this GRC cycle.  ORA and the Utility recommend a third post-test year for this cycle that would provide for an additional increase of $361 million in 2020.  TURN and certain other settling parties oppose the third post-test year.  The other contested issue concerns whether the Utility should be authorized to establish a new balancing account for costs arising from the CPUC’s rulemaking on natural gas leak abatement.  The Utility and certain settling parties support the balancing account.  TURN and certain other settling parties do not.  ORA does not oppose it.  Interested parties filed comments and reply comments on the contested issues and these issues were also discussed at a one-day workshop on August 30, 2016. 

The table below summarizes the differences between the amount of revenue requirement increases included in the Utility’s request, as updated in the Utility’s supplemental testimony filed on February 22, 2016 and its May 27, 2016 rebuttal testimony, and the amount proposed in the settlement agreement:

Year		Increase Requested in GRC Application (in millions)		Increase Proposed in Settlement Agreement (in millions)		Difference(1) (Decrease from GRC Application) (in millions)
2017	$	319	$	88	$	(231)
2018		467		444		(23)
2019		368		361		(7)
2020(2)		N/A		361		N/A

(1)  Rounded for presentation purposes.

(2) Whether or not revenues should be authorized for 2020 is a contested issue.

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The following table shows the difference between the Utility’s requested increases in 2017 revenue requirements by line of business and the amounts proposed in the settlement agreement:

						Increase/(Decrease) Proposed in Settlement Agreement				Difference(1) (Decrease from GRC Application)
(in millions)		Increase Requested in GRC Application
Line of Business:
Electric distribution	$	67	1.6	%	$	(62)	(1.5)	%	$	(128)
Gas distribution		59	3.4			(3)	(0.2)			(62)
Electric generation		193	9.9			153	7.8			(40)
2017 revenue requirement increases	$	319	4.0	%	$	88	1.1	%	$	(231)

(1) Rounded for presentation purposes.

The following table shows the differences, by line of business and cost category, between the amount of revenue requirements included in the GRC application and the amount proposed in the settlement agreement, as well as the differences between the 2016 authorized revenue requirements and (i) the GRC application and (ii) the amounts proposed in the settlement agreement:

							Increase/		Increase/
	Amounts		Amounts				(Decrease)		(Decrease)
	Requested in		Proposed in				2016 Amounts		2016 Amounts
(in millions) (1)	2017 GRC		Settlement		Difference		vs. 2017 GRC		vs. Settlement
Line of Business:	Application		Agreement		(Decrease)		Application		Agreement
Electric distribution	$	4,279	$	4,151	$	(128)	$	67	$	(62)
Gas distribution		1,801		1,738		(62)		59		(3)
Electric generation		2,155		2,115		(40)		193		153
Total revenue requirements	$	8,235	$	8,004	$	(231)	$	319	$	88
Cost Category:
(in millions) (1)
Operations and maintenance	$	1,825	$	1,794	$	(31)		161		131
Customer services		361		334		(27)		42		15
Administrative and general		975		912		(62)		(36)		(99)
Less: Revenue credits		(140)		(152)		(12)		(9)		(21)
Franchise fees, taxes other than
income, and other adjustments		184		170		(14)		146		132
Depreciation (including costs of asset
removal), return, and income taxes		5,030		4,946		(84)		15		(70)
Total revenue requirements	$	8,235	$	8,004	$	(231)	$	319	$	88

(1) Rounded for presentation purposes.

The settlement agreement proposed reductions in the following areas forecast in the GRC application.  For gas distribution, reductions are proposed for corrosion control, leak management, gas operations technology, and new business.  For electric distribution, reductions are proposed for overhead maintenance, capacity, technology, mapping and records, reliability, substation management, new business, and undergrounding work.  For electric distribution, the capital-related reductions are offset in part by increases in the replacement and installation of additional units in specific asset areas.  For electric generation, the settlement agreement proposed to move costs related to Diablo Canyon seismic studies from the GRC to the Utility’s Energy Resource Recovery Account proceeding.  Proposed reductions in the customer service area largely relate to the removal of certain costs from the forecast related to residential rate reform implementation.  Some of these costs would be recoverable through the existing Residential Rates Reform Memorandum Account, and the Utility could seek recovery of the remaining costs in a future filing with the CPUC.  Additionally, a number of company-wide reductions, including reductions to the Short-Term Incentive Plan and certain employee benefits, are proposed in the settlement agreement.

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Balancing Accounts

The settlement agreement proposes to retain certain existing balancing accounts, including the Tax Act Memo Account that was first established following the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, and to eliminate certain memorandum and balancing accounts that are no longer necessary.  In addition to the contested balancing account for natural gas leak abatement mitigation costs, the settlement agreement proposes one new tax-related memorandum account to track the impact on the revenue requirement from certain types of changes in tax laws or regulations.

Capital Additions and Rate Base

The settlement agreement proposes capital expenditures of $3.9 billion for 2017 for the portions of the Utility’s business addressed in the GRC.  Proposed capital expenditures are lower than the amount included in the GRC application of $4.0 billion for 2017, consistent with the provisions of the settlement agreement.  While the settlement agreement proposes overall revenue requirement increases for 2018 and 2019, it does not specify capital expenditures for those years.  At the August 30, 2016 workshop, the Utility estimated authorized capital expenditures of $3.6 billion for 2018 and $3.5 billion for 2019, based on a calculation method that is subject to CPUC approval,as compared to its request of approximately $4.0 billion each year. The Utility is unable to predict if the CPUC will approve its proposed calculation method.

The settlement agreement proposes a 2017 weighted average rate base of $24.3 billion for the portions of the Utility’s business reviewed in the GRC, compared with the Utility’s request of $24.5 billion.  The $200 million difference is primarily due to the lower level of capital expenditures agreed to in the settlement.  At the August 30, 2016 workshop, the Utility also estimated a weighted average rate base of $25.4 billion for 2018 and $26.3 billion for 2019, compared with the Utility’s request of $25.7 billion and $26.9 billion, respectively.

Evidentiary hearings were held on September 1, 2016.  A workshop was held on January 11, 2017 to further explore the three-year versus four-year rate case cycle.  Under the current schedule, a final CPUC decision is expected to be issued in the first half of 2017.  On March 17, 2016, the CPUC issued a decision to allow the authorized revenue requirement changes to become effective on January 1, 2017, even if the final decision is issued after that date.

PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the settlement agreement.

2015 Gas Transmission and Storage Rate Case

On June 23, 2016, the CPUC approved a final decision in phase one of the Utility’s 2015 GT&S rate case. The decision adopts the revenue requirements that the Utility is authorized to collect through rates beginning August 1, 2016, to recover its costs of gas transmission and storage services for the 2015 GT&S rate case period (see table below).The decision authorizes the Utility to collect, over a 36-month period, the difference between adopted revenue requirements and amounts previously collected in rates, retroactive to January 1, 2015.  Accounting rules allow the Utility to recognize revenues in a given year only if they will be collected from customers within 24 months of the end of that year.  As a result, the Utility will complete recording $102 million of the retroactive revenue requirement increase in the first quarter of 2017.

The phase one decision excludes from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted.  The decision permanently disallows $120 million of that amount and orders that the remaining $576 million be subject to a third party audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding.  The decision also establishes various cost caps that will increase the risk of overspend over the current rate case cycle including new one-way capital balancing accounts.  In the second quarter of 2016, the Utility incurred charges of $190 million for capital expenditures that the Utility believes are probable of disallowance based on the decision. This includes $134 million to the net plant balance for 2011 through 2014 capital expenditures in excess of adopted amounts and $56 million for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts.  The Utility took an additional charge of $29 million in the fourth quarter of 2016 related to 2015 through 2018 capital expenditures that are forecasted to exceed authorized amounts.  Additional charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending.

The phase one decision denies the Utility’s request for full balancing account treatment for recovery of authorized transportation and storage revenue requirements for non-core customers, and instead continues the revenue sharing mechanism authorized in the 2011 GT&S rate case that subjects a portion of the Utility’s transportation and storage revenue requirement to market risk.

The phase one decision also authorizes the Utility’s request for cost recovery of up to $157 million for the construction of Line 407, a 25.5 mile, 30-inch pipeline in the Sacramento Valley expected to be built during this rate case period.  The authorized revenue requirements will begin when Line 407 becomes operational.  The decision also authorizes the Utility to track costs exceeding $157 million in a memorandum account.  A reasonableness review of all costs for Line 407 will take place in the next GT&S rate case.

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On August 1, 2016, TURN, ORA, and Indicated Shippers filed an application for rehearing of the phase one decision.  The application indicates that the decision contains language suggesting that the authorized revenue requirement is to comply with new federal and state safety mandates and should be removed from the final decision, allows recovery of shareholder costs in rates, and improperly sequences the calculation of the San Bruno Penalty and the ex parte disallowance.  The Utility filed a response on August 16, 2016.  The Utility cannot predict when or if the CPUC will grant the rehearing or if it will adopt the parties’ recommendations.

On December 1, 2016, the CPUC approved a final decision in phase two of the Utility’s 2015 GT&S rate case, regarding the $850 million penalty assessed in the Penalty Decision.  The final phase two decision applies $689 million of the $850 million penalty (81 percent) to capital expenditures and the remaining $161 million (19 percent) to expenses, and then reduces the 2015 revenue requirement by $72 million for the five-month delay caused by the Utility’s violation of the CPUC ex parte communication rules in this proceeding ($57 million of the $72 million total ex parte disallowance was recognized in 2016 and the remaining $15 million will be recognized in the first quarter of 2017).  The final decision also approves the Utility’s list of programs which meet the CPUC’s definition of “safety related,” the costs of which are to be funded through the $850 million penalty.

The following table shows the revenue requirement amounts adopted in the Utility’s 2015 GT&S rate case including adjustments for the $850 million Penalty Decision disallowance and the ex parte disallowance:

(in millions)	2015		2016		2017		2018
Revenue Requirement Before Adjustments	$	1,046	$	1,110	$	1,220	$	1,324
San Bruno Penalty Expense Allocation		(161)
San Bruno Penalty Capital Revenue Requirement Allocation		5		(47)		(93)		(93)
Other Expense Adjustments		(3)		(2)		(2)		(1)
Adjusted Ex Parte Penalty		(72)
Final Phase Two Revenue Requirement	$	815	$	1,061	$	1,125	$	1,230

The final phase two decision adopts total weighted average rate base of $2.8 billion in 2015, $2.8 billion in 2016, $3.0 billion in 2017, and $3.5 billion in 2018.  The final phase two decision reduces rate base by the full amount of the disallowed capital expenditures but does not remove the associated deferred taxes, which the Utility believes creates a normalization violation.  In the final decision, the CPUC authorizes the Utility to establish a Tax Normalization Memorandum Account to track relevant costs and clarifies that it does not intend the rate base offset or the penalty generally, to create tax timing differences.  The final decision also affirms the CPUC’s intention to comply with normalization rules and to avoid the potential adverse consequences of a finding of a normalization violation by the IRS.  Pursuant to the final phase two decision, on February 6, 2017, the Utility submitted an advice letter to the CPUC to provide 30 days advance notice of the Utility’s request to the IRS for a private letter ruling to determine whether the adopted ratebase offset complies with IRS normalization rules.  The final decision authorizes the Utility to subsequently seek an appropriate adjustment to its revenue requirements and rate base if the IRS finds a normalization violation.

On January 4, 2017, TURN, ORA and Indicated Shippers filed an application for rehearing of the phase two decision.  Specifically, the application argues that the decision inappropriately sequenced the San Bruno Penalty and the ex parte ratemaking disallowance.  The Utility filed a response on January 19, 2017.  The Utility cannot predict when or if the CPUC will grant the rehearing.

With the addition of a third attrition year, the Utility’s next GT&S cycle will begin in 2019.  The decision requires the Utility to file its next GT&S application in 2017.

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FERC Transmission Owner Rate Cases

On July 29, 2015, the Utility requested a 2016 retail electric transmission revenue requirement of $1.515 billion, a $314 million increase over the previous year’s authorized revenue requirement of $1.201 billion.  The Utility’s proposed rates went into effect on March 1, 2016, subject to refund, and pending a final decision by the FERC.  On September 1, 2016, the Utility and other settling parties (including the CPUC) filed a motion at the FERC for approval of a settlement proposing that the Utility’s 2016 retail electric transmission revenue requirement be set at $1.331 billion, a $130 million increase over the previous year’s authorized revenue requirement.  The Utility also filed a motion on September 1, 2016, requesting the implementation of interim rates, which was an agreed upon term of the settlement.  The motion was granted and, as a result, the interim rates became effective for wholesale customers on September 1, 2016 and for retail customers on October 1, 2016.  The FERC approved the settlement on November 17, 2016.

On July 29, 2016, the Utility filed a rate case at the FERC requesting a 2017 retail electric transmission revenue requirement of $1.718 billion, a $387 million increase over the 2016 revenue requirement of $1.331 billion.  The forecasted network transmission rate base for 2017 is $6.7 billion.  The Utility is also seeking a return on equity of 10.9% which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO.  In the filing, the Utility forecasted that it will make investments of $1.296 billion in 2017 in various capital projects. 

On September 30, 2016, the FERC issued an order accepting the Utility’s July 2016 filing and set it for settlement negotiations.  The order set an effective date for rates of March 1, 2017, and made the rates subject to hearing and refund.  The next settlement conference is scheduled for March 16 and March 17, 2017.

CPUC Cost of Capital

On February 6, 2017, the Utility and other California IOUs entered into a MOU with the CPUC, ORA, and TURN to extend the next cost of capital application filing deadline two years to April 22, 2019 for the year 2020.  To implement the MOU, on February 7, 2016, the IOUs, ORA, and TURN filed with the CPUC a petition for modification of prior CPUC decisions addressing the cost of capital.  If the petition for modification is approved as submitted it would reduce the Utility’s ROE from 10.40% to 10.25% and reset the Utility’s authorized cost of long-term debt and preferred stock beginning January 1, 2018.  The long-term debt cost reset will reflect actual embedded costs as of the end of August 2017 and forecasted interest rates for the new long-term debt scheduled to be issued for the remainder of 2017 and all of 2018.The Utility’s current capital structure of 52% common equity, 47% long-term debt, and 1% preferred equity would remain unchanged. 

If and once the petition for modification is granted by the CPUC, each IOU will submit to the CPUC in September 2017 its respective updated cost of capital and corresponding revenue requirement impacts with an effective date of January 1, 2018.  While the actual changes to the Utility’s revenue requirement resulting from the petition for modification will not be known until the Utility’s filing in September 2017, the Utility estimates that its annual revenue requirement will be reduced by approximately $100 million, beginning in 2018.  These estimates are based on current and forecasted market interest rates.  Changes in market interest rates can have material effects on the cost of the Utility’s future financings and consequently on the estimated change in annual revenue requirements.

The Utility’s cost of capital adjustment mechanism would not operate in 2017 but could operate in 2018 to change the cost of capital for 2019.  If the mechanism is activated for 2019, the Utility’s cost of capital, including its new ROE of 10.25%, will be adjusted according to the existing terms of the mechanism.  Concurrently with the petition for modification, the Utility and other California IOUs sent a letter to the executive director of the CPUC requesting that the existing April 2017 filing due date for the 2018 cost of capital be deferred while the CPUC is considering the petition for modification.  On February 13, 2017, the executive director of the CPUC granted the request. As extended, the Utility and the other California IOUs would file their next cost of capital applications 60 days after the effective date of the CPUC decision on the petition for modification, or April 20, 2017, whichever is later, if the CPUC does not grant the petition for modification.The Utility expects that the CPUC may issue a decision in the first half of 2017.

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Diablo Canyon Nuclear Power Plant

Joint Proposal for Plant Retirement

On August 11, 2016, the Utility submitted an application to the CPUC to retire Diablo Canyon at the expiration of its current operating licenses in 2024 and 2025 and replace it with a portfolio of energy efficiency and GHG-free resources.  The application implements a joint proposal between the Utility and the Friends of the Earth, Natural Resources Defense Council, Environment California, International Brotherhood of Electrical Workers Local 1245, Coalition of California Utility Employees, and Alliance for Nuclear Responsibility.

The application and joint proposal include a voluntary increase in the Utility’s target for RPS-eligible resources to 55%, effective in 2031 through 2045, as compared to the state’s goal of 50% renewables.The parties to the joint proposal proposed that the Utility be authorized to procure GHG-free replacement resources in three competitive procurement tranches: in Tranche 1, the Utility would be authorized to obtain 2,000 gross GWh of energy efficiency savings to be implemented over the 2018 to 2024 time period; in Tranche 2, the Utility would be authorized to procure through a solicitation 2,000 GWh of GHG-free energy resources that will commence energy deliveries or add energy efficiency projects to the system in the 2025 to 2030 time period; and in Tranche 3, the Utility would commit to a voluntary 55% RPS beginning in 2031, and would maintain this voluntary commitment through 2045 or until superseded by action of the state legislature or the CPUC.  The three tranches of resource procurement in the application and joint proposal are not intended to specify all energy resources that will be needed to ensure the orderly replacement of Diablo Canyon. Instead, the Utility expects that the full solution will be addressed in ongoing CPUC proceedings. 

Costs associated with energy efficiency projects or programs in Tranche 1 and Tranche 2 would be recovered through the Utility’s electric public purpose program rates as non-bypassable charges, consistent with the existing recovery mechanisms for energy efficiency program costs.  GHG-free energy resources costs from Tranche 2 are proposed to be recovered through a non-bypassable cost allocation mechanism called the Clean California Charge that (1) equitably allocates costs and benefits, such as RPS or Resource Adequacy credits, associated with the procurement among responsible load-serving entities, and (2) determines the net capacity costs of such procurement consistent with the methodology for the allocation of net capacity costs laid out by the CPUC.  Costs associated with procurement for Tranche 3 would be recovered through a separate renewable non-bypassable charge.

The application seeks confirmation from the CPUC that the Utility’s full investment in Diablo Canyon and authorized rate of return will be recovered in rates by the time the facility ceases operations.  Additionally, the Utility requests that the CPUC pre-approve the recovery of certain costs related to the closure of the Diablo Canyon.  These include the non-bypassable cost allocation mechanism for procurement of GHG-free energy and the recovery of $1.3 billion for administration and acquisition of the new Tranche 1 energy efficiency procurement as authorized energy efficiency funding, subject to return of all unspent funds; the recovery of employee retention and retraining and development programs to continue safe and efficient operation of Diablo Canyon through the end of its license periods, estimated at approximately $360 million; and a community mitigation program to compensate San Luis Obispo County for the decline in local economic stimulus provided by Diablo Canyon through a transition period ending in 2025, estimated at $85 million. The Utility also seeks cost recovery of approximately $50 million in costs related to the federal and state Diablo Canyon license renewal process.

More than 40 parties have submitted responses and protests to the Utility’s application.  A prehearing conference on the application was held on October 6, 2016 and public participation hearings were held in San Luis Obispo on October 20, 2016.  On November 18, 2016, a scoping memo was issued that set the schedule and determined that land issues would be out of the scope of this proceeding.  In December 2016, the Utility filed with the CPUC the community impact mitigation program settlement agreement of $85 million, compared to $50 million included in the original joint proposal filed on August 11, 2016.  Intervenor testimonies were submitted to the CPUC in January 2017.  Several intervenors indicated their support to retire Diablo Canyon at the expiration of its current operating licenses in 2024 and 2025.  Several parties argued, however, that a component of the employee retention program and community impact mitigation program be funded by shareholders.  Several intervenors also submitted proposals for modifications to certain aspects of the three GHG-free replacement tranches. Several parties recommended that the license renewal project cost recovery request be rejected and/or be paid for by both customers and shareholders.  There were no direct challenges to the Diablo Canyon remaining net book value cost recovery proposal.  Rebuttal testimony and comments on the community impact mitigation program settlement agreement are scheduled to be submitted to the CPUC on March 17, 2017 and evidentiary hearings are scheduled to take place in April 2017.  Opening and reply briefs are due on May 26, 2017 and June 9, 2017, respectively.  The Utility expects that a final decision will be issued by the end of 2017.Upon CPUC approval of the application and such approval becoming final and non-appealable, the Utility will withdraw its license renewal application currently pending before the NRC.  PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the application.

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California State Lands Commission Lands Lease

On June 28, 2016, California State Lands Commission approved a new lands lease for the intake and discharge structures at Diablo Canyon to run concurrently with Diablo Canyon’s current operating licenses, until Diablo Canyon Unit 2 ceases operations in August 2025.  The Utility believes that the approval of the new lease will ensure sufficient time for the Utility to identify and bring online a portfolio of GHG-free replacement resources.  The Utility will submit a future lease extension request to address the period of time required for plant decommissioning, which under NRC regulations can take as long as 20 years.  On August 28, 2016, the World Business Academy (WBA) filed a writ in the Los Angeles Superior Court.  WBA asserts that the State Lands Commission committed legal error when it determined that the short term lease extension for an existing facility was exempt from review under the California Environmental Quality Act.  If the petitioner prevails in its challenge, the State Lands Commission could be required to perform an environmental review of the new lands lease.  The court has set a trial date of July 11, 2017, with the petitioner’s opening brief due February 27, 2017, opposition briefs due April 24, 2017, and reply briefs due May 22, 2017. 

Asset Retirement Obligations

The Utility expects that the decommissioning of Diablo Canyon will take many years after the expiration of its current operating licenses.  Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP.  Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.  The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

On March 1, 2016, the Utility submitted its updated decommissioning cost estimate with the CPUC.  The estimated undiscounted cost to decommission the Utility’s nuclear power plants increased by approximately $1.4 billion, for a total estimated cost of $4.8 billion, due to increased estimated costs related to spent fuel storage, staffing, and out-of-state waste disposal.  The Utility requested that the CPUC authorize the collection of increased annual revenue requirements beginning on January 1, 2017 based onthese updated cost estimates.

While the NDCTP forecast includes employee severance program estimates, it does not include estimated costs related to the joint proposal’s employee retention and retraining and development programs, and the San Luis Obispo County community mitigation program described above.  The Utility intends to conduct a site-specific decommissioning study to update the 2015 NDCTP forecast and to submit the study to the CPUC by mid-2019. 

On July 15, 2016, the assigned CPUC commissioner and ALJ issued a scoping memo for the Utility’s 2015 NDCTP and excluded from the scope of the proceeding the issue on whether the Utility should be required to present additional analysis for a license extension scenario for Diablo Canyon, as a result of the Utility’s announcement of its plan to not seek relicensing of Diablo Canyon beyond its current operating authority.  The scoping memo also adopts within the scope of the proceeding a reasonableness review of the Utility’s estimated updated cost to decommission the Utility’s nuclear power plants and of the forecasts of certain expenses and the decommissioning trust funds’ rates of return.  Evidentiary hearings took place in September 2016 and opening briefs were submitted on October 14, 2016.  Intervenor parties proposed several major recommendations including a reduction to the total spent nuclear fuel storage forecast, a reduction to the large component (reactor vessels, steam generators, and other large plant components) removal cost estimate, and a reduction to the waste disposal estimate.  Additionally, intervenors asserted that the CPUC should not permit the Utility to increase its Diablo Canyon-related revenue requirement at this time as it has not demonstrated its current estimate is reasonable. Parties also claimed that the Utility has not justified its increase to security costs and decommissioning oversight contractor staff costs.  No party challenged the Utility’s decommissioning trust funds rates of return or cost escalation assumptions.  Reply briefs were submitted on October 31, 2016.  Intervenor parties reiterated that the Utility has not justified increases in costs due to large component removal, site security, decommissioning contractor staff, spent nuclear fuel storage, and waste disposal.  The Utility confirmed that the testimony and work papers support the cost increases as well as the total estimate to decommission Diablo Canyon.

The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued in accordance with GAAP was $3.5 billion at December 31, 2016, which includes an $818 million adjustment to reflect the increased cost estimates and a $115 million increase resulting from the joint proposal described above, and $2.5 billion at December 31, 2015.  These estimates are based on decommissioning cost studies, prepared in accordance with the CPUC requirements.  Changes in these estimates could materially affect the amount of the recorded ARO for these assets.

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As of December 31, 2016, the nuclear decommissioning trust accounts’ total fair value was $2.9 billion.  Changes in the estimated costs, the timing of decommissioning or the assumptions underlying these estimates could cause material revisions to the estimated total cost to decommission. 

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 consultant’s work began in the second quarter of 2016.

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 any next actions in the proceeding.  The timing, scope and potential outcome of the investigation are uncertain.

2014 – 2015 Energy Efficiency Incentive Awards

On December 15, 2016, the CPUC approved a final 2014 - 2015 Energy Efficiency Incentive Award of $16.3 million, compared to the Utility’s request of $19.1 million.  The award includes a $5.8 million reduction reflecting the approved settlement agreement related to the rehearing of the 2006-2008 customer energy efficiency shareholder incentives.  The settlement agreement requires the Utility to reduce future energy efficiency shareholder incentives by $29.1 million, which will be applied in installments of $5.8 million per year for five years, provided that the Utility has sufficient energy efficiency incentive awards to offset that amount.  Due to the application of the first offset of $5.8 million, the required future energy efficiency reduction currently corresponds to $23.3 million.  If shareholder incentives are insufficient to offset this amount, the offset in the following year will be increased by the shortfall.  At its discretion, the Utility may increase the amount of the offset to reduce the remaining offset obligation more quickly.  If the amount has not been fully offset at the end of five years, the balance will be credited against future energy efficiency program spending.

LEGISLATIVE AND REGULATORY INITIATIVES

The California Legislature and the CPUC have adopted requirements, policies, and decisions to improve and refine gas and electric safety citation programs, implement new state law requirements applicable to natural gas storage facilities,accommodate the growth in distributed electric generation resources (including solar installations), increase the amount of renewable energy delivered to customers, promote customer energy efficiency and demand response programs, and foster the development of a state-wide electric vehicle charging infrastructure to encourage the use of electric vehicles. 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 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.  

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.

Gas and Electric Safety Citation Program

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.  The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports.  Under both the gas and electric programs, the SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000.  The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day.

On September 29, 2016, the CPUC issued a final decision adopting improvements and refinements to its gas and electric safety citation programs.  Specifically, the final decision refines the criteria for the SED to use in determining whether to issue a citation and the amount of penalty, sets an administrative limit of $8 million per citation issued, makes self-reporting voluntary in both gas and electric programs, adopts detailed criteria for the utilities to use to voluntarily self-report a potential violation, and refines other issues in the programs.  The decision also merges the rules applicable to its gas and electric safety citation programs into a single set of rules that replace the previous safety citation programs and adopts non-substantive changes to these programs so that the programs can be similar in structure and process where appropriate.

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Natural Gas Storage Facilities

On January 6, 2016, the California Governor ordered the 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.  On February 5, 2016, the DOGGR adopted the emergency regulations.  The Utility implemented the regulations and submitted an Underground Storage Risk and Integrity Management Plan on August 5, 2016 that is pending DOGGR approval.

Additionally, in September 2016, the California Governor signed SB 887 directing DOGGR and CARB to develop permanent regulations for gas storage facility operations in California, which are expected to be finalized in the second half of 2017.  The PHMSA has also issued interim final rules effective January 18, 2017 regulating gas storage facilities at the federal level.  The Utility may incur significant costs to comply with the new regulations related to (1) the development of a natural gas leak prevention and response program, (2) the development of a plan for corrosion monitoring and evaluation, (3) proactive replacement of equipment at risk of failure, and (4) a review of risk management plans to consider new risk factors.  The Utility plans to file an advice letter with the CPUC in the first quarter of 2017 to request a memorandum account to track the future incremental costs associated with implementing the new regulations.  Upon approval, a subsequent application would be submitted to the CPUC for recovery of the incremental costs being tracked.  The Utility is unable to estimate the timing and outcome of such request.

New Renewable Energy Targets

In October 2015, the California Governor signed SB 350 into law, which became effective January 1, 2016.  SB 350 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 three year 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.

In December 2016, the CPUC issued the first of a series of decisions to implement the RPS-related provisions of SB 350.  The decision addressed compliance periods and procurement quantity requirements.  Subsequent rulings and decisions are expected in 2017 to address scope and implementation details.

Additionally, as stated above, the Utility’s application and joint proposal toretire Diablo Canyon include a voluntary increase in the Utility’s target for RPS-eligible resources to 55%, effective in 2031 through 2045, as compared to the state’s goal of 50% renewables.

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 DERs.  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 gridthat would allow customers to choose new advanced energy supply technologies and services to meet their needs consistent with safe, reliable and affordable electric service. 

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On January 24, 2017, the CPUC convened a workshop aimed at informing the development of a CPUC framework to evaluate grid-modernization investments.  The workshop was attended by the California IOUs, the DER industry, consumer advocates, the DOE, and the CPUC’s Energy Division staff.  The Energy Division staff is expected to develop a grid modernization investment framework in the first quarter of 2017.  Additionally, on February 9, 2017, the CPUC issued a decision approving two out of three of the Utility’s proposed field demonstration projects to test various distribution-related services that DERs might provide to the Utility.  The Utility in unable to predict when a final CPUC decision approving, disapproving, or modifying the Utility’s electric distribution resources plan will be issued.

Integrated Distributed Energy Resources  – Regulatory Incentives Pilot Program

On April 4, 2016, the assigned CPUC commissioner and ALJ issued a ruling proposing to establish, on a pilot basis, an interim program offering regulatory incentives to the Utility and the other two large California IOUs for the deployment of cost-effective DERs.  The ruling assumed that the incentive would take the form of an additional payment to the Utility of 3.5% (grossed up for taxes) of the payments made to the DER provider(s).  The ruling also stated that it did not intend for this phase to adopt a new regulatory framework or business model for the California electric utilities.

On September 1, 2016, the assigned CPUC commissioner and ALJ issued an amended scoping memo and ruling that re-categorized all activities in the proceeding as rate-setting, consolidated remaining issues into one phase, and proposed a revised regulatory incentive pilot to test how an earnings opportunity affects DER sourcing.  On December 22, 2016, the CPUC issued a final decision in the proceeding which authorizes a pilot to test a regulatory incentive mechanism through which the Utility will earn a 4% pre-tax incentive on annual payments for DERs, as well as test a regulatory process that will allow the Utility to competitively solicit DER services to defer distribution infrastructure.  Each utility is required to conduct at least one pilot, but may conduct up to three additional pilots.

Electric Rate Reform and Net Energy Metering (NEM)

On July 3, 2015, the CPUC approved a final decision to authorize the California IOUs to gradually flatten their tiered residential electric rate structures to two tiers by January 2019. The decision approved higher 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 (known as “default time-of-use rates”) unless customers elect otherwise. 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.  The new rules became effective for new NEM customers in December 2016, when the Utility reached its NEM cap of 2,409 MW.  New NEM customers will be required to pay an interconnection fee, will be charged for energy use 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.  Unlike the initial NEM tariff, there is no cap on the total capacity of distributed generation that can be installed under the new rules, and there is no size limitation on the projects, so long as projects over 1MW pay actual interconnection costs. On March 7, 2016, the Utility and certain other parties, including TURN and CUE, filed applications for rehearing.  The Utility requested that the CPUC vacate its January 2016 decision that the Utility asserts contains legal and factual errors.  Many parties argued that the CPUC failed to complete its duties under AB 327, which required the CPUC to evaluate the costs and benefits of NEM.  On September 15, 2016, the CPUC voted to deny the applications for rehearing, concluding that good cause had not been established to grant a rehearing and that the NEM decision adopted a successor tariff as required.  The CPUC indicated that it may revisit the NEM successor tariff in 2019.

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Electric Vehicle (EV) Infrastructure Development

In December 2014, the CPUC issued a decision adopting a policy to expand the California utilities’ role in developing 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 EV charging stations and the associated infrastructure.  On December 15, 2016, the CPUC issued a final decision establishing a three-year EV program of $130 million (approximately $109 million in capital expenditures) to deploy up to 7,500 charging stations.  Further deployment of light-duty EV infrastructure will be considered in a second phase of the proceeding.

Transportation Electrification (TE) Application

SB 350 orders the CPUC, in consultation with the CARB and the CEC, to direct electrical corporations to file applications for programs and investments to accelerate widespread TE.  In September 2016, the CPUC directed the large IOUs to file projects to accelerate TE in the state, including both one-year projects (of up to $20 million total) and two to five-year programs with a requested revenue requirement determined by the utility.  On January 20, 2017, the Utility filed itsTE application with the CPUC requesting a total of up to $253 million (approximately $211 million in capital expenditures) in program funding over five years (2018 - 2022) primarily related to make-ready infrastructure for TE in medium to heavy-duty sectors.  Protests are due March 6, 2017 and a prehearing conference is scheduled for March 16, 2017.  The Utility expects a decision to be issued within 12 to 18 months.

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; the reporting of safety and reliability measures for natural gas storage facilities; 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, 2016, $299 million and $135 million was accrued in the Consolidated Balances Sheets for estimated undiscounted remediation costs associated with the Topock site and the Hinkley 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

PG&E Corporation, mainly through its ownership of the Utility, and 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-trading purposes (i.e. risk mitigation) and not for speculative purposes.  The Utility’s risk management activities include the use of physical 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 $7 million and $2 million at December 31, 2016 and 2015, respectively.  During 2016, the Utility’s approximate high, low, and average values-at-risk were $7 million, $1 million and $4 million, respectively. During 2015, the value-at-risk amounts were $2 million, $1 million and $2 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, 2016 and 2015, 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 $13million and $11 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.

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, 2016	$	69	$	(11)	$	58		3		39
December 31, 2015		64	$	(11)	$	53		4		39

(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.

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CRITICAL ACCOUNTING POLICIES

The preparation of the 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 materially from these estimates and assumptions.  These accounting 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, 2016, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $9.9billion and regulatory liabilities (including current regulatory 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 $283 million in 2016 for capital spending that was disallowed related to the Penalty Decision.  The Utility incurred charges of $219 million in 2016 for capital expenditures that will be disallowed based on the final phase two decision in its 2015 GT&S rate case.  Additionally, the Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected.  (See “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

Loss Contingencies

As discussed below, PG&E Corporation and the Utility have recorded material accruals for environmental remediation liabilities and for various enforcement and legal matters, and have recorded insurance receivables for third-party claims.

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.

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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, 2016 and 2015, the Utility’s accruals for undiscounted gross environmental liabilities were $958million and $969 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. 

Enforcement and Litigation 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.  Management has made significant estimates and assumptions about accruals related to the Butte fire.  At December 31, 2016, the Utility’s accrual for the Butte fire was $690 million.  Actual results may differ materially from these estimates and assumptions.  (See “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

Insurance Receivable

The Utility has liabilityinsurance from various insurers, which provides coverage for third party claims.  The Utility records insurance recoveries only when a third party claim is recorded and it is deemed probable that a recovery of that claim will occur and the Utility can reasonably estimate the amount or its range. The assessment of whether recovery is probable or reasonably possible, and whether the recovery or a range of recoveries is estimable, often involves a series of complex judgments about future events.Insurance recoveries are reviewed quarterlyand estimates are adjusted to reflect the impactof all known information, including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, discussions with insurers and other information and events pertaining to a particular matter.  Management has made significant estimates and assumptions about insurance recoveries related to the Butte fire. (See “Enforcement and Litigation Matters” and “Legal and Regulatory Contingencies” in Note 13of 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, 2016, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was $4.7 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 2017 is 7.2%, gradually decreasing to the ultimate trend rate of 4.5% in 2025 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 5.3% compares to a ten-year actual return of 7.3%.

The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 696 Aa-grade non-callable bonds at December 31, 2016.  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 2016 Pension		Benefit Obligation at
(in millions)	Assumption		Costs		December 31, 2016
Discount rate	(0.50)	%	$	109	$	1,319
Rate of return on plan assets	(0.50)	%		68		-
Rate of increase in compensation	0.50	%		59		306

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

	Increase		Increase in 2016		Increase in Accumulated
	(Decrease) in		Other Postretirement		Benefit Obligation at
(in millions)	Assumption		Benefit Costs		December 31, 2016
Health care cost trend rate	0.50	%	$	4	$	58
Discount rate	(0.50)	%		4		134
Rate of return on plan assets	(0.50)	%		10		-

NEW ACCOUNTING PRONOUNCEMENTS

See Note2 of the Notes to the Consolidated Financial Statements.

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  These statements reflect management’s judgment and opinions which are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this 2016 Form 10-K.  These forward-looking statements relate to, among other matters, estimated losses, 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.  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 Butte fire litigation, and whether the Utility’s insurance is sufficient to cover the Utility’s liability resulting therefrom or whether insurance is otherwise available; and whether additional investigations and proceedings in connection with the Butte fire will be opened;  

● the timing and outcomes of the 2017 GRC, TO rate case, cost of capital proceeding, and other ratemaking and regulatory proceedings;

● the terms of probation and the monitorship imposed in the sentencing phase of the Utility’s federal criminal trial on January 26, 2017, the timing and outcomes of the debarment proceeding and potential remedial and other measures that could be imposed on the Utility as a result of that proceeding, the SED’s unresolved enforcement matters relating to the Utility’s compliance with natural gas-related laws and regulations, and 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 outcomes 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, or of a potential settlement, and of the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office investigations in connection with communications between the Utility’s personnel and CPUC officials, whether additional criminal or regulatory investigations or enforcement actions are commenced with respect to allegedly improper communications, and the extent to which such matters negatively affect the final decisions to be issued in the Utility’s ratemaking proceedings;

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

● whether the Utility can control its costs within the authorized levels of spending, and successfully implement a streamlined organizational structure and achieve project savings, 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 timing and outcome of the complaint filed by the CPUC and certain other parties with the FERC on February 2, 2017; the complaint requests that the Utility provide an open and transparent planning process for its capital transmission projects that do not go through the California ISO’s Transmission Planning Process in order to allow for participation and input from interested parties.  The planning process that may result from come out of the proceeding may impact the scope and timing of capital transmission projects that the Utility will execute in the future;

● 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 the SED’s investigations of potential violations identified through audits, investigations, or self-reports including inconnection with the Utility’s February 2017 self-report related to its customer service representatives’ drug and alcohol testing program;  

● the outcome 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, environmental laws and regulations;

● 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 maintenance costs of the Utility electric transmission facilities;

● 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 that may affect the Utility’s ability to continue operating Diablo Canyon; whether the CPUC approves the joint proposal that will phase out the Utility’s Diablo Canyon nuclear units at the expiration of their licenses in 2024 and 2025; whether the Utility obtains the approvals required to withdraw its NRC application to renew the two Diablo Canyon operating licenses; whether the State Lands Commission could be required to perform an environmental review of the new lands lease as a result of the WBA assertion that the State Lands Commission committed legal error when it determined that the short term lease extension for an existing facility was exempt from review under the California Environmental Quality Act; and whether the Utility will be able to successfully implement its retention and retraining and development programs for Diablo Canyon employees, and whether these programs will be recovered in rates;  

● whether the Utility is successful in ensuring physical security of its critical assets and 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 and its third party vendors and contractors (who host, maintain, modify and update some of the Utility’s systems) are able to protect the Utility’s 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 impact of droughts or other weather-related conditions or events, wildfires (such as the Butte fire), climate change, natural disasters, acts of terrorism, war, 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; whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events; and whether the Utility’s insurance coverage is available for these types of claims and sufficient to cover the Utility’s liability;

● how the CPUC and the CARB implement state environmental laws relating to GHG, renewable energy targets, energy efficiency standards, DERs, 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;

● the impact of the SB 887 directing DOGGR and CARB to develop permanent regulations for gas storage facility operations in California to comply with new safety and reliability measures, as well the impact of the PHMSA rules effective January 18, 2017 regulating gas storage facilities at the federal level;  

● 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 is successful in addressing the impact of growing distributed and renewable generation resources, changing customer demand for natural gas and electric services, and an increasing number of customers departing for CCAs;

● 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;

● 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 their 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 jury’s verdict in the federal criminal trial of the Utility and its possible conviction, 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 impact of the corporate tax reform considered by the new federal administration and 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;  

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● changes in the regulatory and economic environment, including potential changes affecting renewable energy sources and associated tax credits, as a result of the new federal administration; 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,
	2016		2015		2014
Operating Revenues
Electric	$	13,864	$	13,657	$	13,658
Natural gas		3,802		3,176		3,432
Total operating revenues		17,666		16,833		17,090
Operating Expenses
Cost of electricity		4,765		5,099		5,615
Cost of natural gas		615		663		954
Operating and maintenance		7,354		6,951		5,638
Depreciation, amortization, and decommissioning		2,755		2,612		2,433
Total operating expenses		15,489		15,325		14,640
Operating Income		2,177		1,508		2,450
Interest income		23		9		9
Interest expense		(829)		(773)		(734)
Other income, net		91		117		70
Income Before Income Taxes		1,462		861		1,795
Income tax provision (benefit)		55		(27)		345
Net Income		1,407		888		1,450
Preferred stock dividend requirement of subsidiary		14		14		14
Income Available for Common Shareholders	$	1,393	$	874	$	1,436
Weighted Average Common Shares Outstanding, Basic		499		484		468
Weighted Average Common Shares Outstanding, Diluted		501		487		470
Net Earnings Per Common Share, Basic	$	2.79	$	1.81	$	3.07
Net Earnings Per Common Share, Diluted	$	2.78	$	1.79	$	3.06
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,
	2016		2015		2014
Net Income	$	1,407	$	888	$	1,450
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $1, $0, and $10, at respective dates)		(2)		(1)		(14)
Net change in investments
(net of taxes of $0, $12, and $17 at respective dates)		-		(17)		(25)
Total other comprehensive income (loss)		(2)		(18)		(39)
Comprehensive Income		1,405		870		1,411
Preferred stock dividend requirement of subsidiary		14		14		14
Comprehensive Income Attributable to Common Shareholders	$	1,391	$	856	$	1,397
See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2016		2015
ASSETS
Current Assets
Cash and cash equivalents	$	177	$	123
Restricted cash		7		234
Accounts receivable
Customers (net of allowance for doubtful accounts of $58 and $54
at respective dates)		1,252		1,106
Accrued unbilled revenue		1,098		855
Regulatory balancing accounts		1,500		1,760
Other		801		286
Regulatory assets		423		517
Inventories
Gas stored underground and fuel oil		117		126
Materials and supplies		346		313
Income taxes receivable		160		155
Other		283		338
Total current assets		6,164		5,813
Property, Plant, and Equipment
Electric		52,556		48,532
Gas		17,853		16,749
Construction work in progress		2,184		2,059
Other		2		2
Total property, plant, and equipment		72,595		67,342
Accumulated depreciation		(22,014)		(20,619)
Net property, plant, and equipment		50,581		46,723
Other Noncurrent Assets
Regulatory assets		7,951		7,029
Nuclear decommissioning trusts		2,606		2,470
Income taxes receivable		70		135
Other		1,226		1,064
Total other noncurrent assets		11,853		10,698
TOTAL ASSETS	$	68,598	$	63,234
See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2016		2015
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,516	$	1,019
Long-term debt, classified as current		700		160
Accounts payable
Trade creditors		1,495		1,414
Regulatory balancing accounts		645		715
Other		433		398
Disputed claims and customer refunds		236		454
Interest payable		216		206
Other		2,323		1,997
Total current liabilities		7,564		6,363
Noncurrent Liabilities
Long-term debt		16,220		15,925
Regulatory liabilities		6,805		6,321
Pension and other postretirement benefits		2,641		2,622
Asset retirement obligations		4,684		3,643
Deferred income taxes		10,213		9,206
Other		2,279		2,326
Total noncurrent liabilities		42,842		40,043
Commitments and Contingencies (Note 13)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares;
506,891,874 and 492,025,443 shares outstanding at respective dates		12,198		11,282
Reinvested earnings		5,751		5,301
Accumulated other comprehensive loss		(9)		(7)
Total shareholders' equity		17,940		16,576
Noncontrolling Interest - Preferred Stock of Subsidiary		252		252
Total equity		18,192		16,828
TOTAL LIABILITIES AND EQUITY	$	68,598	$	63,234
See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2016		2015		2014
Cash Flows from Operating Activities
Net income	$	1,407	$	888	$	1,450
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		2,755		2,612		2,433
Allowance for equity funds used during construction		(112)		(107)		(100)
Deferred income taxes and tax credits, net		1,030		693		690
Disallowed capital expenditures		507		407		116
Other		379		326		286
Effect of changes in operating assets and liabilities:
Accounts receivable		(473)		(177)		13
Butte-related insurance receivable		(575)		-		-
Inventories		(24)		37		(22)
Accounts payable		180		(55)		(61)
Butte-related third-party claims		690		-		-
Income taxes receivable/payable		(5)		43		376
Other current assets and liabilities		83		(288)		218
Regulatory assets, liabilities, and balancing accounts, net		(1,214)		(244)		(1,642)
Other noncurrent assets and liabilities		(219)		(355)		(67)
Net cash provided by operating activities		4,409		3,780		3,690
Cash Flows from Investing Activities
Capital expenditures		(5,709)		(5,173)		(4,833)
Decrease in restricted cash		227		64		3
Proceeds from sales and maturities of nuclear decommissioning
trust investments		1,295		1,268		1,336
Purchases of nuclear decommissioning trust investments		(1,352)		(1,392)		(1,334)
Other		13		22		114
Net cash used in investing activities		(5,526)		(5,211)		(4,714)
Cash Flows from Financing Activities
Borrowings (repayments) under revolving credit facilities		-		-		(260)
Net issuances (repayments) of commercial paper, net of discount
of $6, $3, and $2 at respective dates		(9)		683		(583)
Short-term debt financing		500		-		300
Short-term debt matured		-		(300)		-
Proceeds from issuance of long-term debt, net of premium, discount and
issuance costs of $17, $27 and $17 at respective dates		983		1,123		2,308
Repayments of long-term debt		(160)		-		(889)
Common stock issued		822		780		802
Common stock dividends paid		(921)		(856)		(828)
Other		(44)		(27)		29
Net cash provided by financing activities		1,171		1,403		879
Net change in cash and cash equivalents		54		(28)		(145)
Cash and cash equivalents at January 1		123		151		296
Cash and cash equivalents at December 31	$	177	$	123	$	151

87

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(726)	$	(684)	$	(633)
Income taxes, net		231		77		501
Supplemental disclosures of noncash investing and financing
activities
Common stock dividends declared but not yet paid	$	248	$	224	$	217
Capital expenditures financed through accounts payable		403		440		339
Noncash common stock issuances		20		21		21
Terminated capital leases		18		-		71
See accompanying Notes to the Consolidated Financial Statements.

88

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, 2013	456,670,424	$	9,550	$	4,742	$	50	$	14,342	$	252	$	14,594
Net income	-		-		1,450		-		1,450		-		1,450
Other comprehensive income	-		-		-		(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
Cumulative effect of change
in accounting principle	-		-		29		-		29		-		29
Net income	-		-		1,407		-		1,407		-		1,407
Other comprehensive loss	-		-		-		(2)		(2)		-		(2)
Common stock issued, net	14,866,431		842		-		-		842		-		842
Stock-based compensation amortization	-		74		-		-		74		-		74
Common stock dividends declared	-		-		(972)		-		(972)		-		(972)
Preferred stock dividend requirement of
subsidiary	-		-		(14)		-		(14)		-		(14)
Balance at December 31, 2016	506,891,874	$	12,198	$	5,751	$	(9)	$	17,940	$	252	$	18,192
See accompanying Notes to the Consolidated Financial Statements.

89

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

	Year ended December 31,
	2016		2015		2014
Operating Revenues
Electric	$	13,865	$	13,657	$	13,656
Natural gas		3,802		3,176		3,432
Total operating revenues		17,667		16,833		17,088
Operating Expenses
Cost of electricity		4,765		5,099		5,615
Cost of natural gas		615		663		954
Operating and maintenance		7,352		6,949		5,635
Depreciation, amortization, and decommissioning		2,754		2,611		2,432
Total operating expenses		15,486		15,322		14,636
Operating Income		2,181		1,511		2,452
Interest income		22		8		8
Interest expense		(819)		(763)		(720)
Other income, net		88		87		77
Income Before Income Taxes		1,472		843		1,817
Income tax provision (benefit)		70		(19)		384
Net Income		1,402		862		1,433
Preferred stock dividend requirement		14		14		14
Income Available for Common Stock	$	1,388	$	848	$	1,419
See accompanying Notes to the Consolidated Financial Statements.

90

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2016		2015		2014
Net Income	$	1,402	$	862	$	1,433
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $1, $1, and $6, at respective dates)		(1)		(2)		(8)
Total other comprehensive income (loss)		(1)		(2)		(8)
Comprehensive Income	$	1,401	$	860	$	1,425
See accompanying Notes to the Consolidated Financial Statements.

91

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2016		2015
ASSETS
Current Assets
Cash and cash equivalents	$	71	$	59
Restricted cash		7		234
Accounts receivable
Customers (net of allowance for doubtful accounts of $58 and $54
at respective dates)		1,252		1,106
Accrued unbilled revenue		1,098		855
Regulatory balancing accounts		1,500		1,760
Other		801		284
Regulatory assets		423		517
Inventories
Gas stored underground and fuel oil		117		126
Materials and supplies		346		313
Income taxes receivable		159		130
Other		282		338
Total current assets		6,056		5,722
Property, Plant, and Equipment
Electric		52,556		48,532
Gas		17,853		16,749
Construction work in progress		2,184		2,059
Total property, plant, and equipment		72,593		67,340
Accumulated depreciation		(22,012)		(20,617)
Net property, plant, and equipment		50,581		46,723
Other Noncurrent Assets
Regulatory assets		7,951		7,029
Nuclear decommissioning trusts		2,606		2,470
Income taxes receivable		70		135
Other		1,110		958
Total other noncurrent assets		11,737		10,592
TOTAL ASSETS	$	68,374	$	63,037
See accompanying Notes to the Consolidated Financial Statements.

92

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2016		2015
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	1,516	$	1,019
Long-term debt, classified as current		700		160
Accounts payable
Trade creditors		1,494		1,414
Regulatory balancing accounts		645		715
Other		453		418
Disputed claims and customer refunds		236		454
Interest payable		214		203
Other		2,072		1,750
Total current liabilities		7,330		6,133
Noncurrent Liabilities
Long-term debt		15,872		15,577
Regulatory liabilities		6,805		6,321
Pension and other postretirement benefits		2,548		2,534
Asset retirement obligations		4,684		3,643
Deferred income taxes		10,510		9,487
Other		2,230		2,282
Total noncurrent liabilities		42,649		39,844
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		8,050		7,215
Reinvested earnings		8,763		8,262
Accumulated other comprehensive income		2		3
Total shareholders' equity		18,395		17,060
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	68,374	$	63,037
See accompanying Notes to the Consolidated Financial Statements.

93

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2016		2015		2014
Cash Flows from Operating Activities
Net income	$	1,402	$	862	$	1,433
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		2,754		2,611		2,432
Allowance for equity funds used during construction		(112)		(107)		(100)
Deferred income taxes and tax credits, net		1,042		714		731
Disallowed capital expenditures		507		407		116
Other		306		263		226
Effect of changes in operating assets and liabilities:
Accounts receivable		(475)		(177)		16
Butte-related insurance receivable		(575)		-		-
Inventories		(24)		37		(22)
Accounts payable		179		(2)		(55)
Butte-related third-party claims		690		-		-
Income taxes receivable/payable		(29)		38		395
Other current assets and liabilities		112		(315)		168
Regulatory assets, liabilities, and balancing accounts, net		(1,214)		(244)		(1,642)
Other noncurrent assets and liabilities		(219)		(340)		(66)
Net cash provided by operating activities		4,344		3,747		3,632
Cash Flows from Investing Activities
Capital expenditures		(5,709)		(5,173)		(4,833)
Decrease in restricted cash		227		64		3
Proceeds from sales and maturities of nuclear decommissioning
trust investments		1,295		1,268		1,336
Purchases of nuclear decommissioning trust investments		(1,352)		(1,392)		(1,334)
Other		13		22		29
Net cash used in investing activities		(5,526)		(5,211)		(4,799)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount
of $6, $3, and $2 at respective dates		(9)		683		(583)
Short-term debt financing		500		-		300
Short-term debt matured		-		(300)		-
Proceeds from issuance of long-term debt, net of premium, discount and
issuance costs of $17, $27, and $14 at respective dates		983		1,123		1,961
Repayments of long-term debt		(160)		-		(539)
Preferred stock dividends paid		(14)		(14)		(14)
Common stock dividends paid		(911)		(716)		(716)
Equity contribution from PG&E Corporation		835		705		705
Other		(30)		(13)		43
Net cash provided by financing activities		1,194		1,468		1,157
Net change in cash and cash equivalents		12		4		(10)
Cash and cash equivalents at January 1		59		55		65
Cash and cash equivalents at December 31	$	71	$	59	$	55

94

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(717)	$	(675)	$	(618)
Income taxes, net		244		77		500
Supplemental disclosures of noncash investing and financing
activities
Capital expenditures financed through accounts payable	$	403	$	440	$	339
Terminated capital leases		18		-		71
See accompanying Notes to the Consolidated Financial Statements.

95

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, 2013	$	258	$	1,322	$	5,821	$	7,427	$	13	$	14,841
Net income		-		-		-		1,433		-		1,433
Other comprehensive income		-		-		-		-		(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
Cumulative effect of change
in accounting principle		-		-		-		24		-		24
Net income		-		-		-		1,402		-		1,402
Other comprehensive loss		-		-		-		-		(1)		(1)
Equity contribution		-		-		835		-		-		835
Common stock dividend		-		-		-		(911)		-		(911)
Preferred stock dividend		-		-		-		(14)		-		(14)
Balance at December 31, 2016	$	258	$	1,322	$	8,050	$	8,763	$	2	$	18,395
See accompanying Notes to the Consolidated Financial Statements.

96

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 serving 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.  A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations and cash flows during the period in which such change occurred.

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 periodsin 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.

97

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 or four 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

Prior to October 2016, restricted cash primarily consisted 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 atweighted-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.

98

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)	2016		2015
Electricity generating facilities (1)	5 to 100	$	11,308	$	9,860
Electricity distribution facilities	15 to 55		29,836		28,476
Electricity transmission facilities	15 to 75		11,412		10,196
Natural gas distribution facilities	5 to 60		11,362		10,397
Natural gas transmission and storage facilities	5 to 65		6,491		6,352
Construction work in progress			2,184		2,059
Total property, plant, and equipment			72,593		67,340
Accumulated depreciation			(22,012)		(20,617)
Net property, plant, and equipment		$	50,581	$	46,723

(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 3.73% in 2016, 3.80% in 2015, and 3.77% in 2014.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 $51million and $112million during2016, $48 million and $107 million during2015, and $45 million and $100 million during 2014.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2016 and 2015, including nuclear decommissioning obligations:

(in millions)		2016		2015
ARO liability at beginning of year	$	3,643	$	3,575
Revision in estimated cash flows		968		13
Accretion		194		169
Liabilities settled		(121)		(114)
ARO liability at end of year	$	4,684	$	3,643

99

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.  InMarch2016, the Utility submitted its updated decommissioningcost estimate to the CPUC.  As a result, the estimated undiscounted cost to decommission the Utility’s nuclear power plants increased by approximately $1.4billion. The change in total estimated cost resulted in an $818 million adjustment to theARO. The adjustment was a result of increased estimatedcosts related to spentfuel storage, staffing, and out-of-state waste disposal. 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 recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue untilthose costs are fully recovered. The Utility requested that the CPUC authorize the collection ofincreased annual revenue requirementsbeginning on January 1, 2017 based ontheseupdated cost estimates.

On August 11, 2016, the Utility submitted an application to the CPUC to retire Diablo Canyon at the expiration of its current operating licenses in 2024 (Unit 1) and 2025 (Unit 2). The application includes a joint proposal between the Utility and certain interested parties, entered into on June 20, 2016, which resulted in a $115 million increase to the ARO recognized on the Consolidated Balance Sheets in June 2016.

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 $3.5 billion and $2.5 billion at December 31, 2016and 2015, respectively.The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $5.1 billion and $3.5 billion at December 31, 2016 and2015 (or $7.3 billion in future dollars), respectively.  These estimates are based on the 2016 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.  (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. 

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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, 2016,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, 2016, 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 13herein.

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, 2016 consisted of the following:

	Pension		Other
(in millions, net of income tax)	Benefits		Benefits		Total
Beginning balance	$	(23)	$	16	$	(7)
Other comprehensive income before reclassifications:
Unrecognized prior service cost
(net of taxes of $37 and $15, respectively)		54		(21)		33
Unrecognized net actuarial loss
(net of taxes of $45 and $15, respectively)		(64)		21		(43)
Regulatory account transfer
(net of taxes of $5 and $0, respectively)		7		-		7
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $3 and $6, respectively) (1)		5		9		14
Amortization of net actuarial loss
(net of taxes of $10 and $2, respectively) (1)		14		2		16
Regulatory account transfer
(net of taxes of $13 and $8, respectively) (1)		(18)		(11)		(29)
Net current period other comprehensive loss		(2)		-		(2)
Ending balance	$	(25)	$	16	$	(9)

(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, 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.)

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

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Recently Adopted Accounting Guidance

Share-Based Payment Accounting

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718), which amends the existing guidance relating to the accounting for share-based payment awards issued to employees, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.  PG&E Corporation and the Utility have adopted this standard as of the fourth quarter of 2016. 

ASU 2016-09 requires recognition of excess tax benefits and deficiencies in the income statement, which resulted in the recognition of $6.3 millionin income tax benefit for PG&E Corporation and the Utility for the year ended December 31, 2016.  Previously, these amounts were recognized in additional paid-in capital.  Previously unrecognized excess tax benefits were reclassified via a cumulative-effect adjustment.  ASU 2016-09 also requires excess tax benefits and deficiencies to be prospectively excluded from assumed future proceeds in the calculation of diluted shares when calculating diluted earnings per share utilizing the treasury stock method.  The effect of this change on diluted EPS is immaterial.  Additionally, excess income tax benefits from stock-based compensation arrangements are now classified as cash flows from operating activities rather than as cash flows from financing activities, which resulted in an increase to cash flows from operating activities of approximately $7.2 millionfor the year ended December 31, 2016. 

Furthermore, ASU 2016-09 requires, on a retrospective basis, that employee taxes paid for withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities.  As such, the consolidated statements of cash flows for PG&E Corporation and the Utility for the prior periods presented were restated.  This change resulted in an increase to cash flows from operating activities and a decrease to cash flows from financing activities of $34.6 million, $26.8 million, and $13.2 millionfor the years ended December 31, 2016, 2015, and 2014, respectively.

PG&E Corporation and the Utility have elected to continue to estimate forfeitures expected to occur to determine the amount of compensation cost to be recognized in each period and have not changed their policy on statutory withholding requirements and will continue to allow the employee to withhold up to the minimum statutory withholding requirements.

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 standardizes reporting practices related to the fair value hierarchy for all investments for which fair value is measured using net asset value per share.  PG&E Corporation and the Utility adopted this guidance effective January 1, 2016. The adoption of this standard did not have a material impact on their Consolidated Financial Statements.  All prior periods presented in these Consolidated Financial Statements reflect the retrospective adoption of this guidance.(See Notes10 and 11 below.)

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.  PG&E Corporation and the Utility adopted this guidance effective January 1, 2016.  The adoption of this guidance did not have a material impact on their Consolidated Financial Statements.

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 the existing guidance relating to the presentation of debt issuance costs.  The amendments in this ASU 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 adopted this guidance effective January 1, 2016 and applied the requirements retrospectively for all periods presented.  The adoption of this guidance did not have a material impact on their Consolidated Financial Statements.  PG&E Corporation and the Utility restated $105 million and $103 million, respectively, of debt issuance costs as of December 31, 2015 with no impact to net income or total shareholders’ equity previously reported.  All prior periods presented in these Consolidated Financial Statements reflect the retrospective adoption of this guidance.

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Accounting Standards Issued But Not Yet Adopted

Restricted Cash

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230), which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows.  The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted.  PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Statements of Cash Flows.

Recognition of Lease Assets and Liabilities

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing guidance relating to the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements.  Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheet, which were previously not recognized.The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019 with retrospective application.  PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 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 the existing guidance relating to 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.

Revenue Recognition Standard

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance, effective January 1, 2018.  The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdiction, and capital markets and to provide more useful information to users of financial statements through improved disclosure requirements.  PG&E Corporation and the Utility do not plan to early adopt the standard and are currently reviewing all revenue streams and evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.  The Utility does not expect ASU 2014-09 to materially impact the timing or recognition of revenue generated through the sale and delivery of electricity and natural gas to customers.  However, the Utility continues to consider the impacts of outstanding industry-related issues being addressed by the American Institute of CPAs’ Revenue Recognition Working Group and the FASB’s Transition Resource Group.

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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)	2016		2015		Period
Pension benefits (1)	$	2,429	$	2,414	Indefinitely (3)
Deferred income taxes(1)		3,859		3,054	47 years
Utility retained generation(2)		364		411	9 years
Environmental compliance costs (1)		778		748	32 years
Price risk management (1)		92		138	10 years
Unamortized loss, net of gain, on reacquired debt (1)		76		94	26 years
Other		353		170	Various
Total long-term regulatory assets	$	7,951	$	7,029

(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) 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, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2016		2015
Cost of removal obligations (1)	$	5,060	$	4,605
Recoveries in excess of AROs (2)		626		631
Public purpose programs(3)		567		600
Other		552		485
Total long-term regulatory liabilities	$	6,805	$	6,321

(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.

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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)	2016		2015
Electric distribution	$	132	$	380
Utility generation		48		122
Gas distribution and transmission		541		493
Energy procurement		132		262
Public purpose programs		106		155
Other		541		348
Total regulatory balancing accounts receivable	$	1,500	$	1,760

	Payable
	Balance at December 31,
(in millions)	2016		2015
Gas distribution and transmission	$	48	$	-
Energy procurement		13		112
Public purpose programs		264		244
Other		320		359
Total regulatory balancing accounts payable	$	645	$	715

The electric distribution and utility generationaccounts track the collection of revenue requirements approved in the GRC.  The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case.  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.

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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)		2016		2015
PG&E Corporation
Senior notes:
Maturity	Interest Rates
2019	2.40%		350		350
Unamortized discount, net of premium and debt issuance costs			(2)		(2)
Total PG&E Corporation long-term debt			348		348
Utility
Senior notes:
Maturity	Interest Rates
2017	5.625%		700		700
2018	8.25%		800		800
2020	3.50%		800		800
2021	3.25% to 4.25%		550		550
2022 through 2046	2.45% to 6.35%		12,775		11,775
Less: current portion			(700)		-
Unamortized discount, net of premium and debt issuance costs			(161)		(156)
Total senior notes, net of current portion			14,764		14,469
Pollution control bonds:
Maturity	Interest Rates
Series 2004 A-D, due 2023(1)	4.75%		345		345
Series 2009 A-D, due 2026 (2)	variable rate(4)		149		309
Series 1996 C, E, F, 1997 B due 2026(3)	variable rate(5)		614		614
Less: current portion			-		(160)
Total pollution control bonds			1,108		1,108
Total Utility long-term debt, net of current portion			15,872		15,577
Total consolidated long-term debt, net of current portion		$	16,220	$	15,925

(1)The Utility has obtained credit support from an insurance company for these bonds.

(2)Each series of these bonds is supported by a separate direct-pay letter of credit.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent. Series C and D pollution control bonds were redeemed on November 30, 2016.

(3)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.

(4) At December 31, 2016, the interest rate on these bonds was 0.74%.

(5) At December 31, 2016, the interest rate on these bonds ranged from 0.72% - 0.73%.

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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 sales 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.

Repayment Schedule

PG&E Corporation’s and the Utility’s combined long-termdebt principal repayment amounts at December 31,2016 are reflected in the table below:

(in millions,
except interest rates)	2017		2018		2019		2020		2021		Thereafter		Total
PG&E Corporation
Average fixed interest rate		-		-		2.40%		-		-		-		2.40%
Fixed rate obligations	$	-	$	-	$	350	$	-	$	-	$	-	$	350
Utility
Average fixed interest rate		5.625%		8.25%		-		3.50%		3.80%		4.84%		4.94%
Fixed rate obligations	$	700	$	800	$	-	$	800	$	550	$	13,120	$	15,970
Variable interest rate
as of December 31, 2016		-		-		0.74%		0.73%		-		-		0.73%
Variable rate obligations (1)	$	-	$	-	$	149	$	614	$	-	$	-	$	763
Total consolidated debt	$	700	$	800	$	499	$	1,414	$	550	$	13,120	$	17,083

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

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, 2016:

		Credit			Letters of		Commercial
	Termination	Facility			Credit		Paper		Facility
(in millions)	Date	Limit			Outstanding		Outstanding		Availability
PG&E Corporation	April 2021	$	300	(1)	$	-	$	-	$	300
Utility	April 2021		3,000	(2)		41		1,016		1,943
Total revolving credit facilities		$	3,300		$	41	$	1,016	$	2,243

(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 31,2016, PG&E Corporation’s average outstanding commercial paper balance was $84million and the maximum outstanding balance during the year was $176 million.  For 2016, the Utility’s average outstanding commercial paper balance was $837million and the maximum outstanding balance during the year was $1.4billion.  There were no bank borrowings for PG&E Corporation or the Utility in 2016.

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Revolving Credit Facilities

In June 2016, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2020 to April 27, 2021.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 one additional period. 

Borrowings under each credit agreement (other than swingline 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 credit agreement and between 0.8% and 1.275% under the Utility’s credit agreement. The applicable margin for base rate loans will range between 0% and 0.475% under PG&E Corporation’s credit agreement and between 0% and 0.275% under the Utility’s credit agreement.  In addition, the facility fee under PG&E Corporation’s and the Utility’s 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’s and the Utility’s commercial paper programs are used primarily to fund temporary financing needs.  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 withPG&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 2016, the average yield on outstanding PG&E Corporation and Utility commercial paper was 0.63% and 0.64%, respectively.

Other Short-term Borrowings

In March 2016, the Utility entered into a $250 million floating rate unsecured term loan that matures on February 2, 2017.  Additionally, in December 2016, the Utility issued a $250 million unsecured senior floating rate note that matures on November 30, 2017.  The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.

NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 506,891,874shares of common stock outstanding at December 31, 2016.  PG&E Corporation held all of the Utility’s outstanding common stock at December 31,2016.

During 2016, PG&E Corporation sold 2.6 million shares of common stock under the February 2015 equity distribution agreement for cash proceeds of $149 million, net of commissions paid of $1.3 million.  As of December 31, 2016, the remaining gross sales available under this agreement were $275 million.

In August 2016, PG&E Corporation sold 4.9 million shares of its common stock in an underwritten public offeringfor net cash proceeds of $309 million.

In addition, during 2016, PG&E Corporation sold 7.4 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 $364million.

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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 the first quarter of 2016, the Board of Directors of PG&E Corporation declared a common stock dividend of $0.455 per share.  In May 2016, the Board of Directors of PG&E Corporation adopted a new quarterly common stock dividend of $0.49 per share. In 2016, total dividends were $1.925 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%.  Additionally, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on a weighted average over five years.  At December 31, 2016, the Utility had restricted net assets of $15.8 billion and was limited to $25 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.  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 13,826,995 shares were available for future awards at December 31, 2016.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2016, 2015, and 2014:

(in millions)	2016		2015		2014
Restricted stock units	$	53	$	47	$	42
Performance shares		55		46		36
Total compensation expense (pre-tax)	$	108	$	93	$	78
Total compensation expense (after-tax)	$	64	$	55	$	47

The amount of share-based compensation costs capitalized during 2016, 2015, and 2014 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 after 2014 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 2016, 2015, and 2014 was $56.68, $53.30, and $43.76, respectively.  The total fair value of restricted stock units that vested during 2016, 2015, and 2014 was $36million, $57 million, and $34 million, respectively.  The tax benefit from restricted stock units that vested during each period was not material.In general, forfeitures are recorded rateably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2016, $37million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.22years.

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The following table summarizes restricted stock unit activity for 2016:

	Number of	Weighted Average Grant-
	Restricted Stock Units	Date Fair Value
Nonvested at January 1	1,972,899	$	47.33
Granted	776,312	$	56.68
Vested	(770,968)	$	46.79
Forfeited	(55,233)	$	49.65
Nonvested at December 31	1,923,010	$	51.26

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 either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period or, for a small number of awards, an internal PG&E Corporation metric.  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 for the total shareholder return based awards or the grant-date market value of PG&E Corporation common stock for internal metric based awards.  The weighted average grant-date fair value for performance shares granted during2016,2015, and 2014 was $53.61, $68.27, and $51.81 respectively.  There was no tax benefit associated with performance shares during each of these periods.In general, forfeitures are recorded rateably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.As of December 31, 2016, $40 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of1.57 years.

The following table summarizes activity for performance shares in2016:

	Number of	Weighted Average Grant-
	Performance Shares	Date Fair Value
Nonvested at January 1	1,450,612	$	59.24
Granted	1,233,884		53.61
Vested	(777,719)		51.81
Forfeited (1)	(67,922)		58.20
Nonvested at December 31	1,838,855	$	58.65
(1)Includes performance shares that expired with zero value as performance targets were not met.

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 75million shares of $25 par value preferred stock and 10 million shares of $100par value preferred stock.  At December 31, 2016 and December 31, 2015, 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 between4.36%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.

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At December 31, 2016, 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, 2016, 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 $14million of dividends on preferred stock in each of 2016, 2015, and 2014.

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 2016, 2015, and 2014.

	Year Ended December 31,
(in millions, except per share amounts)	2016		2015		2014
Income available for common shareholders	$	1,393	$	874	$	1,436
Weighted average common shares outstanding, basic		499		484		468
Add incremental shares from assumed conversions:
Employee share-based compensation		2		3		2
Weighted average common share outstanding, diluted		501		487		470
Total earnings per common share, diluted	$	2.78	$	1.79	$	3.06

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 asset and 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 guidancein 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)	2016		2015		2014		2016		2015		2014
Current:
Federal	$	(105)	$	(89)	$	(84)	$	(105)	$	(88)	$	(84)
State		(70)		11		(41)		(66)		6		(29)
Deferred:
Federal		218		131		396		229		136		426
State		16		(76)		78		16		(69)		75
Tax credits		(4)		(4)		(4)		(4)		(4)		(4)
Income tax provision (benefit)	$	55	$	(27)	$	345	$	70	$	(19)	$	384

The following table describes net deferred income tax liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2016		2015		2016		2015
Deferred income tax assets:
Tax carryforwards		1,851		1,703		1,596		1,462
Other(1)		463		757		402		700
Total deferred income tax assets	$	2,314	$	2,460	$	1,998	$	2,162
Deferred income tax liabilities:
Property related basis differences		10,429		9,656		10,411		9,638
Income tax regulatory asset (2)		1,572		1,244		1,572		1,245
Other(3)		526		766		525		766
Total deferred income tax liabilities	$	12,527	$	11,666	$	12,508	$	11,649
Total net deferred income tax liabilities	$	10,213	$	9,206	$	10,510	$	9,487

(1)Amounts include compensation and benefits, environmental reserve, and customer advances for construction. 

(2)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 3of the Notes to the Consolidated Financial Statements in Item 8.)

(3)Amounts primarily relate to regulatory balancing accounts.  Greenhouse gas allowances are temporary timing differences that reverse through regulatory balancing accounts. 

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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,
	2016		2015		2014		2016		2015		2014
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)	(2.5)		(4.9)		1.4		(2.2)		(4.8)		1.6
Effect of regulatory treatment
of fixed asset differences (2)	(23.7)		(33.6)		(15.0)		(23.4)		(33.7)		(14.7)
Tax credits	(0.8)		(1.3)		(0.7)		(0.8)		(1.3)		(0.7)
Benefit of loss carryback	(1.1)		(1.5)		(0.8)		(1.1)		(1.5)		(0.8)
Non deductible penalties (3)	0.8		4.3		0.3		0.8		4.3		0.3
Other, net(4)	(3.9)		(1.1)		(0.8)		(3.5)		(0.2)		0.4
Effective tax rate	3.8	%	(3.1)	%	19.4	%	4.8	%	(2.2)	%	21.1	%

(1)Includes the effect of state flow-through ratemaking treatment.  In 2016 and 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 costsas authorized by the 2014 GRC decision in all periods presented and by the 2015 GT&S decision which impacts only 2016.  All amounts are impacted by the level of income before income taxes.  The 2014 GRC and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. 

(3)Primarily represents the effects of non-tax deductible fines and penalties associated with the natural gas distribution facilities record-keeping decision for the year ended December 31, 2016 and the effects of the Penalty Decision for the year ended December 31, 2015.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.

(4)In 2016, the amount primarily represents the impact of tax audit settlements.

Unrecognized tax benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation						Utility
(in millions)	2016		2015		2014		2016		2015		2014
Balance at beginning of year	$	468	$	713	$	666	$	462	$	707	$	660
Additions for tax position taken
during a prior year		-		40		7		-		40		7
Reductions for tax position
taken during a prior year		(77)		(349)		(9)		(77)		(349)		(9)
Additions for tax position
taken during the current year		56		64		61		56		64		61
Settlements		(59)		-		(12)		(59)		-		(12)
Balance at end of year	$	388	$	468	$	713	$	382	$	462	$	707

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2016for PG&E Corporation and the Utility was $25 million.

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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, 2016, it is reasonably possible that unrecognized tax benefits will decrease by approximately $70 million within the next 12 months.  PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income.

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, 2016, 2015, and 2014, these amounts were immaterial.

IRS settlements

PG&E Corporation previously participated in the Compliance Assurance Process, 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 participation in the Compliance Assurance Process ended effective with the submission of its 2015 tax return.

PG&E Corporation’s tax returns have been accepted through 2015 except for a few matters, the most significant of which relates to deductible repair costs.  In March 2016, PG&E Corporation reached an agreement with the IRS on deductible electric transmission and distribution repair costs for the 2012 tax year.  The agreement provided that the methodology used in determining the deductible amount should be followed for all subsequent periods, absent any material change in facts.  Deductible repair costs for other lines of business will continue to be subject to examination by the IRS for subsequent years.  The IRS is expected to issue guidance in 2017 that clarifies which repair costs are deductible for the natural gas transmission and distribution businesses. 

Tax years after 2008 remain subject to examination by the state of California.

2015 Gas Transmission and Storage Rate Case

In comments to the proposed decision in phase two of the 2015 GT&S rate case, the Utility questioned whether the methodology employed to calculate the capital disallowance portion of the San Bruno penalty might constitute a normalization violation.  In recognition of this concern, the CPUC, in the final phase two decision, provided the Utility an opportunity to submit a ruling to the IRS for guidance and establish a memorandum account to track the additional revenue that would be recoverable if the method is deemed to be a normalization violation.The Utility anticipates filing the ruling request in early 2017.

As a result of the final phase two decision, PG&E Corporation and the Utilityapplied flow through accounting to property-related timing differences for 2016 and 2015.

Carryforwards

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

	December 31,		Expiration
(in millions)	2016		Year
Federal:
Net operating loss carryforward	$	5,009	2029 - 2036
Tax credit carryforward		116	2029 - 2036
Charitable contribution loss carryforward		192	2017 - 2021
State:
Net operating loss carryforward	$	-	N/A
Tax credit carryforward		51	Various
Charitable contribution loss carryforward		112	2019 - 2021

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, 2016 for these tax attributes.

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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 under the applicable ratemaking mechanism in place as long as 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, 2016 and 2015, respectively, the volumes of the Utility’s outstanding derivatives were as follows:

		Contract Volume
Underlying Product	Instruments	2016	2015
Natural Gas (1)(MMBtus (2))	Forwards and Swaps	323,301,331	333,091,813
	Options	96,602,785	111,550,004
Electricity (Megawatt-hours)	Forwards and Swaps	3,287,397	3,663,512
	Congestion Revenue Rights (3)	278,143,281	216,383,389

(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, 2016, 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	$	91	$	(10)	$	1	$	82
Other noncurrent assets – other		149		(9)		-		140
Current liabilities – other		(48)		10		-		(38)
Noncurrent liabilities – other		(101)		9		3		(89)
Total commodity risk	$	91	$	-	$	4	$	95

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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

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

	Commodity Risk
	For the year ended December 31,
(in millions)	2016		2015		2014
Unrealized gain/(loss) - regulatory assets and liabilities (1)	$	64	$	(6)	$	124
Realized loss - cost of electricity (2)		(53)		(14)		(83)
Realized loss - cost of natural gas (2)		(18)		(10)		(8)
Total commodity risk	$	(7)	$	(30)	$	33

(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, 2016, 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)	2016		2015
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(24)	$	(2)
Related derivatives in an asset position		19		-
Collateral posting in the normal course of business related to
these derivatives		4		-
Net position of derivative contracts/additional collateral
posting requirements(1)	$	(1)	$	(2)

(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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NOTE 10: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets and price risk management instrumentsat 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 are held by PG&E Corporation and not the Utility.

	Fair Value Measurements
	At December 31, 2016
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	105	$	-	$	-	$	-	$	105
Nuclear decommissioning trusts
Short-term investments		9		-		-		-		9
Global equity securities		1,724		-		-		-		1,724
Fixed-income securities		665		527		-		-		1,192
Assets measured at NAV		-		-		-		-		14
Total nuclear decommissioning trusts (2)		2,398		527		-		-		2,939
Price risk management instruments
(Note 9)
Electricity		30		18		181		(18)		211
Gas		-		11		-		-		11
Total price risk management		30		29		181		(18)		222
instruments
Rabbi trusts
Fixed-income securities		-		61		-		-		61
Life insurance contracts		-		70		-		-		70
Total rabbi trusts		-		131		-		-		131
Long-term disability trust
Short-term investments		8		-		-		-		8
Assets measured at NAV		-		-		-		-		170
Total long-term disability trust		8		-		-		-		178
TOTAL ASSETS	$	2,541	$	687	$	181	$	(18)	$	3,575
Liabilities:
Price risk management instruments
(Note 9)
Electricity	$	9	$	12	$	126	$	(21)	$	126
Gas		-		2		-		(1)		1
TOTAL LIABILITIES	$	9	$	14	$	126	$	(22)	$	127

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

(2) Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value.

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	Fair Value Measurements
	At December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	64	$	-	$	-	$	-	$	64
Nuclear decommissioning trusts
Short-term investments		36		-		-		-		36
Global equity securities		1,520		-		-		-		1,520
Fixed-income securities		694		521		-		-		1,215
Assets measured at NAV		-		-		-		-		13
Total nuclear decommissioning trusts (2)		2,250		521		-		-		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
Short-term investments		7		-		-		-		7
Assets measured at NAV		-		-		-		-		158
Total long-term disability trust		7		-		-		-		165
TOTAL ASSETS	$	2,321	$	658	$	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 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.  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 years ended December 31, 2016 and 2015.

Trust Assets

In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.  Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1.  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.

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Fixed-income 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.

On January 1, 2016, PG&E Corporation and the Utility adopted FASB 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) and applied it retrospectively for the periods presented in their Consolidated Financial Statements.  (See Note 2 above.) In accordance with this guidance, investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above.  The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities.  There are no restrictions on the terms and conditions upon which the investments may be redeemed. 

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 Financial Officer, 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, 2016				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	181	$	35	Market approach	CRR auction prices	$	(11.88) - 6.93
Power purchase agreements	$	-	$	91	Discounted cash flow	Forward prices	$	18.07 - 38.80

(1)Represents price per megawatt-hour

	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

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2016and 2015, respectively:

	Price Risk Management Instruments
(in millions)	2016		2015
Asset (liability) balance as of January 1	$	89	$	69
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(34)		20
Asset (liability) balance as of December 31	$	55	$	89

(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, 2016 and 2015,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, 2016 and 2015.

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,
	2016				2015
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation	$	348	$	352	$	348	$	354
Utility		15,813		17,790		14,818		16,422

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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, 2016
Nuclear decommissioning trusts
Short-term investments	$	9	$	-	$	-	$	9
Global equity securities		584		1,157		(3)		1,738
Fixed-income securities		1,156		48		(12)		1,192
Total (1)	$	1,749	$	1,205	$	(15)	$	2,939
As of December 31, 2015
Nuclear decommissioning trusts
Short-term 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

(1)Represents amounts before deducting $333 million and $314 million at December 31, 2016 and2015, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of fixed-income securities by contractual maturity is as follows:

	As of
(in millions)	December 31, 2016
Less than 1 year	$	13
1–5 years		419
5–10 years		255
More than 10 years		505
Total maturities of fixed-income securities	$	1,192

The following table provides a summary of activity for the fixed-income and equity securities:

	2016		2015		2014
(in millions)
Proceeds from sales and maturities of nuclear decommissioning
investments	$	1,295	$	1,268	$	1,336
Gross realized gains on securities held as available-for-sale		18		55		118
Gross realized losses on securities held as available-for-sale		(26)		(37)		(12)

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. 

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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 2016 and 2015:

Pension Plan

(in millions)	2016		2015
Change in plan assets:
Fair value of plan assets at beginning of year	$	13,745	$	14,216
Actual return on plan assets		1,358		(176)
Company contributions		334		334
Benefits and expenses paid		(708)		(629)
Fair value of plan assets at end of year	$	14,729	$	13,745
Change in benefit obligation:
Benefit obligation at beginning of year	$	16,299	$	16,696
Service cost for benefits earned		453		479
Interest cost		715		673
Actuarial (gain) loss		637		(922)
Plan amendments		(91)		1
Transitional costs		-		1
Benefits and expenses paid		(708)		(629)
Benefit obligation at end of year (1)	$	17,305	$	16,299
Funded Status:
Current liability	$	(7)	$	(6)
Noncurrent liability		(2,569)		(2,547)
Net liability at end of year	$	(2,576)	$	(2,553)

(1)PG&E Corporation’s accumulated benefit obligation was $15.6 billion and $14.7 billion at December 31, 2016 and 2015, respectively.

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Postretirement Benefits Other than Pensions

(in millions)	2016		2015
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,035	$	2,092
Actual return on plan assets		167		(26)
Company contributions		52		61
Plan participant contribution		85		68
Benefits and expenses paid		(166)		(160)
Fair value of plan assets at end of year	$	2,173	$	2,035
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,766	$	1,811
Service cost for benefits earned		52		55
Interest cost		76		71
Actuarial (gain) loss		11		(98)
Plan amendments		37		-
Transitional costs		-		1
Benefits and expenses paid		(153)		(146)
Federal subsidy on benefits paid		3		4
Plan participant contributions		85		68
Benefit obligation at end of year	$	1,877	$	1,766
Funded Status: (1)
Noncurrent asset	$	368	$	344
Noncurrent liability		(72)		(75)
Net asset at end of year	$	296	$	269

(1) At December 31, 2016 and 2015, 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)	2016		2015		2014
Service cost	$	453	$	479	$	383
Interest cost		715		673		695
Expected return on plan assets		(828)		(873)		(807)
Amortization of prior service cost		8		15		20
Amortization of net actuarial loss		24		10		2
Net periodic benefit cost		372		304		293
Less: transfer to regulatory account (1)		(34)		34		42
Total expense recognized	$	338	$	338	$	335

(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)	2016		2015		2014
Service cost	$	52	$	55	$	45
Interest cost		76		71		76
Expected return on plan assets		(107)		(112)		(103)
Amortization of prior service cost		15		19		23
Amortization of net actuarial loss		4		4		2
Net periodic benefit cost	$	40	$	37	$	43

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 2017are as follows:

(in millions)	Pension Plan		PBOP Plans
Unrecognized prior service cost	$	(7)	$	15
Unrecognized net loss		22		4
Total	$	15	$	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,
	2016		2015		2014		2016		2015		2014
Discount rate	4.11	%	4.37	%	4.00	%	4.05 - 4.19	%	4.27 - 4.48	%	3.89 - 4.09	%
Rate of future compensation
increases	4.00	%	4.00	%	4.00	%	-		-		-
Expected return on plan
assets	5.30	%	6.10	%	6.20	%	2.80 - 6.00	%	3.20 - 6.60	%	3.30 - 6.70	%

The assumed health care cost trend rate as of December 31, 2016 was7.2%, decreasing gradually to an ultimate trend rate in 2025 and beyond of approximately 4.5%.  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	$	118	$	(120)
Effect on service and interest cost		9		(10)

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 of5.3% compares to a ten-year actual return of 7.3%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 696Aa-grade non-callable bonds at December 31,2016.  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, global REITS, global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios.

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In the Pension Plan, target allocations for 2017 were updated to reflect a 2% increase in global equity investments and a 2% decrease in fixed income investments. Target allocations for PBOP Plans remain unchanged. Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are 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
	2017		2016		2015		2017		2016		2015
Global equity	27	%	25	%	25	%	32	%	32	%	31	%
Absolute return	5	%	5	%	5	%	3	%	3	%	3	%
Real assets	10	%	10	%	10	%	7	%	7	%	8	%
Fixed income	58	%	60	%	60	%	58	%	58	%	58	%
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, 2016 and 2015. 

	Fair Value Measurements
	At December 31,
	2016								2015
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	364	$	369	$	-	$	733	$	247	$	375	$	-	$	622
Global equity		996		-		-		996		903		-		-		903
Real assets		610		-		-		610		581		-		-		581
Fixed-income		1,754		4,774		5		6,533		1,841		4,495		3		6,339
Assets measured at NAV		-		-		-		5,950		-		-		-		5,308
Total	$	3,724	$	5,143	$	5	$	14,822	$	3,572	$	4,870	$	3	$	13,753
PBOP Plans:
Short-term investments	$	33	$	-	$	-	$	33	$	20	$	-	$	-	$	20
Global equity		115		-		-		115		104		-		-		104
Real assets		70		-		-		70		69		-		-		69
Fixed-income		150		656		-		806		150		632		-		782
Assets measured at NAV		-		-		-		1,153		-		-		-		1,065
Total	$	368	$	656	$	-	$	2,177	$	343	$	632	$	-	$	2,040
Total plan assets at fair value							$	16,999							$	15,793

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $97 million and $13 million at December 31, 2016 and 2015, 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 and equity-index futures.  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.

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. 

Fixed-Income

Fixed-incomesecurities 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.

Assets Measured at NAV

On January 1, 2016, PG&E Corporation and the Utility adopted FASB 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) and applied it retrospectively for the periods presented in their Consolidated Financial Statements.  (See Note 2 above.)  In accordance with this guidance, investments in the pension and PBOP plans that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above.  The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets.  These investments include commingled funds that are composed of equity securities traded publicly on exchanges, hedge funds, private real estate funds, and fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities.

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, 2016 and 2015.

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Level 3 Reconciliation

The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2016 and 2015:

(in millions)	Fixed-
For the year ended December 31, 2016	Income
Balance at beginning of year	$	3
Actual return on plan assets:
Relating to assets still held at the reporting date		3
Relating to assets sold during the period		-
Purchases, issuances, sales, and settlements:
Purchases		-
Settlements		(1)
Balance at end of year	$	5
(in millions)	Fixed-
For the year ended December 31, 2015	Income
Balance at beginning of year	$	12
Actual return on plan assets:
Relating to assets still held at the reporting date		(3)
Relating to assets sold during the period		1
Purchases, issuances, sales, and settlements:
Purchases		2
Settlements		(9)
Balance at end of year	$	3

There were no material transfers out of Level 3 in 2016 and 2015.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $334 million to the pension benefit plans and $52 million to the other benefit plans in 2016.  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 2016.  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 2017.

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Benefits Payments and Receipts

As of December 31, 2016, 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
2017	$	739	$	87	$	(8)
2018		781		93		(9)
2019		821		97		(10)
2020		857		103		(10)
2021		892		108		(11)
Thereafter in the succeeding five years		4,879		592		(15)

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 $97 million, $89 million, and $80 million in 2016, 2015, and 2014, 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)	2016		2015		2014
Utility revenues from:
Administrative services provided to PG&E Corporation	$	7	$	6	$	5
Utility expenses from:
Administrative services received from PG&E Corporation	$	74	$	53	$	54
Utility employee benefit due to PG&E Corporation		91		82		70

At December 31, 2016and 2015, the Utility had receivables of $18 million and $22 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 $22 million and $21 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.  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.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.PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters.

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 occurred 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 CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices.

On October 14, 2016, the Cities of San Bruno and San Carlos, ORA, the SED, TURN, and the Utility submitted a status report to the CPUC which proposed an update to the framework for resolving the proceeding.  The revised framework includes a total of 164 communications in the scope of the proceeding.  Throughout 2016, the parties jointly submitted stipulations on all of the communications, and on November 30, 2016, the parties began settlement discussions.  In the event a settlement cannot be reached, the parties will brief the matter based upon the identified communications and some related discovery as well as factual stipulations and agreed upon issues of policy and law for CPUC resolution.  The opening briefs are due on March 24, 2017, and reply briefs are due on April 14, 2017.

The Utility expects that the other parties may argue that the number of violations exceeds the 164 communications referenced in the October 14, 2016 joint status report either because a single communication may have violated more than one rule or because they believe some of the material provided during discovery constitutes impermissible ex parte communications.  The Utility expects to contest many of these assertions.  If the matter does not settle, the CPUC will determine which communications included within the scope of the proceeding were in violation of its rules.  The CPUC will also determine whether to impose penalties or other remedies, as a result of a potential settlement or otherwise.  The CPUC can impose fines up to $50,000 for each violation, and up to $50,000 per day if the CPUC determines that the violation was continuing.  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 broad discretion in determining whether violations are continuing and the amount of penalties to be imposed. 

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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 OII.  In light of recent CPUC decisions, such as the Penalty Decision and the decision in the 2015 GT&S rate case, the Utility expects that such penalties could include fines and future revenue requirement reductions.  In accordance with accounting rules, revenue requirement reductions would be recorded in the period they are incurred and fines would be recorded when considered probable and their amount or range can be reasonably estimated.  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 because it is uncertain how the CPUC will calculate the number of violations or the penalty for any violations.

Finally, in 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel.  The Utility has cooperated with those investigations.  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 required 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 cited 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.  

On August 18, 2016, the CPUC approved a final decision in this investigation.  The CPUC assessed a fine of $25.6 million.  With the $10.85 million citation previously paid in 2015 for the City of Carmel-by-the-Sea (“Carmel”) incident, the total fine imposed on the Utility was $36.5 million.  The remaining $25.6 million was paid in September 2016.  The decision denied the appeals previously filed by the SED and Carmel from the presiding officer’s decision, and closed this proceeding but allowed the parties an opportunity to request that this proceeding be reopened if needed to ensure proper implementation of a compliance plan to be developed by the parties. 

On September 26, 2016, the SED filed an application for rehearing of the CPUC’s decision.  Specifically, the application indicates that the CPUC erred in certain of its determinations (including those related to maximum allowable operating pressure documentation that, if adopted, could result in an additional fine of $7 million), calculations (including thoserelated to the missing DeAnza records violations) and certain other findings, and requests that the CPUC adopt its recommendations.  On October 11, 2016, the Utility submitted its response to the CPUC in which it opposed the SED’s application for rehearing arguing that the application failed to identify a legal error warranting rehearing by the CPUC.  The Utility cannot predict when or if the CPUC will grant the rehearing or if it will adopt the SED’s recommendations.

On October 24, 2016 and November 30, 2016, the Utility held meet and confer sessions with parties to develop remedial measures necessary to address the issues identified in the CPUC decision with the objective of establishing a compliance plan.  On December 16, 2016, the Utility submitted its Initial Gas Distribution Records Compliance Plan that includes feasible and cost-effective measures necessary to improve natural gas distribution system record-keeping. 

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 had been completed and that remediation work, including removal of the encroachments, was 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 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.

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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.  The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports.  Under both the gas and electric programs, the SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000.  The SED may, at its discretion, impose penalties on a daily basis, or on a less than daily basis, for violations that continued for more than one day.  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.  There is also an administrative limit of $8 million per citation issued.

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 penalties or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations, based on the SED’s investigations of incidents reported to the CPUC, or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits or investigations.  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 and other CPUC staff has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.

In September 2016, the Utility reported that it discovered in November 2015 that approximately 550,000 atmospheric corrosion inspections on above-ground gas distribution meters completed in 2014, which constituted 35% of such inspections in 2014, were performed by non-operator qualified personnel.  The Utility did not provide timely notification of such non-compliance to the CPUC.  On December 23, 2016, the SED issued the Utility a citation with a $5.45 million fine related to this self-report.  The citation included a $5.05 million fine for not ensuring that contractor inspectors were operator-qualified, a $350,000 fine for not completing inspections within 39 months from the previous inspections, and a $50,000 fine for not reporting the self-identified violations within ten days of discovery.  The amount of the fine is conditioned upon the Utility implementing certain remedial measures.  The Utility paid the fine in January 2017.

In February 2017, the Utility reported that it discovered in April 2014 that customer service representatives who handle gas emergency calls within the Utility’s call centers are not included in the drug and alcohol testing program as required by PHMSA regulations.  The Utility did not provide timely notification of such non-compliance to the CPUC.  The SED could impose fines on the Utility of $50,000 per violation, and also for failure to timely file a self-report in connection with the non-compliance.  The SED has the authority to issue more than one citation for a series of related incidents and can impose daily fines for continuing violations, and the CPUC can issue an OII and possible additional fines even after the SED has issued a citation.  The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines that could be imposed with respect to this self-report, for the reasons indicated above, or to predict whether the CPUC will open a formal proceeding. 

Federal Matters

Federal Criminal Trial

On June 14, 2016, a federal criminal trial against the Utilitybegan in the United States District Court for the Northern District of California, in San Francisco, on 12 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, and one felony count charging that the Utility obstructed the NTSB investigation into the cause of the San Bruno accident.  On July 26, 2016, the court granted the government’s motion to dismiss one count alleging that the Utility knowingly and willfully failed to retain a strength test pressure record with respect to a distribution feeder main, thereby reducing the total number of counts from 13 to 12.

On August 9, 2016, the jury returned its verdict.  The jury acquitted the Utility on all six of the record-keeping allegations but found the Utility guilty on six felony counts that include one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act.

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On January 26, 2017, the court issued a judgment of conviction sentencing the Utility to a five-year corporate probation period, oversight by a third-party monitorfor a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service.  The Utility has decided not to appeal the convictions.  The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period.  As part of the probation, the Utility is required to retain a third-party monitor.  The goal of the monitorship will be to prevent the criminal conduct with respect to gas pipeline transmission safety that gave rise to the conviction.  To that end, the goal of the monitor will be to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of the gas transmission pipeline system, performs appropriate integrity management assessments on its gas transmission pipelines, and maintains an effective ethics and compliance program and safety related incentive program.

After an initial assessment is conducted and an initial report is prepared by the monitor, the monitor will prepare reports on a semi-annual basis setting forth the monitor’s continued assessment and making recommendations consistent with the goals and scope of the monitorship.  The Utility expects that the monitor will be retained before the end of the second quarter of 2017. 

At December 31, 2016, PG&E Corporation’s and the Utility’s Consolidated Balance Sheets include a $3 million accrual in connection with this matter.  On February 1, 2017, the Utility paid the $3 million fine imposed by the court.  The Utility could incur material costs, not recoverable through rates, in the event of non-compliance with the terms of probation and in connection with the monitorship (including but not limited to the monitor’s compensation or costs resulting from recommendations of the monitor).

Other Federal Matters

In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel.  The Utility has cooperated with those investigations.In addition, in October 2016, the Utility received a grand jury subpoena and letter from the U.S. Attorney for the Northern District of California advising that the Utility is a target of a federal investigation regarding possible criminal violations of the Migratory Bird Treaty Act and conspiracy to violate the act.  The investigation involves a removal by the Utility of a hazardous tree that contained an osprey nest and egg in Inverness, California, on March 18, 2016.  It is uncertain whether any charges will be brought against the Utility as a result of these investigations.

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Other Matters

Butte Fire Litigation

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California.  On April 28, 2016, Cal Firereleased its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures.  Cal Fire’sreport concluded that the wildfire was caused when a Gray Pine tree contactedthe Utility’selectric line which ignited portions of the tree, and determined that the failure by the Utilityand/or its vegetation management contractors, ACRT Inc. and Trees, Inc.,to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. In a press release also issued on April 28, 2016, Cal Fire indicated that it will seek to recover firefighting costs in excess of $90 million from the Utility.

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California for Sacramento County. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council had previously authorized the coordination of all cases in Sacramento County. As of December 31, 2016, complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras,San Francisco, Sacramento, and Amador involving approximately 1,950 individual plaintiffs representing approximately 950 households and their insurance companies. These complaints are part of or are in the process of being added to the two master complaints.Plaintiffs seek to recover damages and other costs, principally based on inverse condemnation and negligence theories of liability.  The number of individual complaints and plaintiffs may increase in the future. 

The Utility continues mediating and settling cases.  The next case management conference is scheduled for March 2, 2017.

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In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees without having been found negligent, through the theory of inverse condemnation.  In addition,the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent.  The Utility believes it was not negligent; however, there can be no assurance that a court or jury would agree with the Utility.  The Utility believes that it is probable that it will incur a loss of at least $750 million for all potential damages described above.  This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and other damages that the Utility could be liable for under the theories of inverse condemnation and/or negligence.

The following table presents changes in the third-party claims liability since December 31, 2015.  The balance for the third-party claims liability is included in Other current liabilitiesin PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Loss Accrual  (in millions)
Balance at December 31, 2015	$	-
Accrued losses		750
Payments		(60)
Balance at December 31, 2016	$	690

In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $27 million.

The Utility believes that it is reasonably possible that it will incur losses related to Butte fire claims in excess of $750 million accrued through December 31, 2016 but is currently unable to reasonably estimate the upper end of the range of losses because it is still in an early stage of the evaluation of claims, the mediation and settlement process, and discovery.  The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors.  As more information becomes known, including additional discovery from the plaintiffs and results from the ongoing mediation and settlement process, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued. 

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of approximately $900 million.  The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range.  The Utility has recorded $625 million for probable insurance recoveries in connection with losses related to the Butte fire.  While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.  In addition, the Utility is pursuing coverage under the insurance policies of its two vegetation management contractors, including under policies where the Utility is listed as an additional insured.  Recoveries of any amounts under these policies are uncertain.

The following table presents changes in the insurance receivable since December 31, 2015.  The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Insurance Receivable (in millions)
Balance at December 31, 2015	$	-
Accrued insurance recoveries		625
Reimbursements		(50)
Balance at December 31, 2016	$	575

If the Utility records losses in connection with claims relating to the Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected in the reporting periods during which additional charges are recorded, depending on whether the Utility is able to record or collect insurance recoveries in amounts sufficient to offset such additional accruals.

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Other Contingencies

PG&E Corporation and the Utility are subject to various claims, lawsuits and regulatory proceedings that separately are not considered material.  Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $45 million at December 31, 2016 and $63 million at December 31, 2015.  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. 

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 and the amount of disallowance can be reasonably estimated.  Capital disallowances are reflected in operating and maintenance expenses in the Consolidated Statements of Income.  Disallowances as a result of the CPUC’s June 23, 2016 final phase one decision and December 1, 2016 final phase two decision in the Utility’s 2015 GT&S rate case, the April 9, 2015 Penalty Decision and the Utility’s Pipeline Safety Enhancement Plan are discussed below.

2015 GT&S Rate Case Disallowance of Capital Expenditures

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The decision permanently disallowed a portion of the 2011 through 2014 capital spending in excess of the amount adopted and established various cost caps that will increase the risk of overspend over the current rate case cycle, including new one-way capital balancing accounts.  As a result, in 2016, the Utility incurred charges of $219 million for capital expenditures that the Utility believes are probable of disallowance based on the decision.  This included $134 million to the net plant balance for 2011 through 2014 capital expenditures in excess of adopted amounts and $85 million for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts.  Additional charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending.

Penalty Decision’s Disallowance of Natural Gas Capital Expenditures

On April 9, 2015, the CPUC issued a decision in its investigative enforcement proceedings against the Utility to impose total penalties of $1.6 billion on the Utility after determining that the Utility had committed numerous violations of laws and regulations related to its natural gas transmission operations (the “Penalty Decision”). In January 2016, the CPUC closed the investigative proceedings.  The total penalty includes (1) a $300 million fine, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million.

On December 1, 2016, the CPUC approved a final phase two decision in the Utility’s 2015 GT&S rate case, which applies $689 million of the $850 million penalty to capital expenditures.  The decision also approves the Utility’s list of programs and projects that meet the CPUC’s definition of “safety related,” the costs of which are to be funded through the $850 million penalty.

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For the twelve months ended December 31, 2016, the Utility recorded charges for disallowed capital spending of $283 million as a result of the Penalty Decision.  The cumulative charges at December 31, 2016, and the additional future charges that will be recognized in the first quarter of 2017 are shown in the following table:

	Twelve Months		Cumulative		Future
	Ended		Charges		Charges
		December 31,		December 31,	and		Total
(in millions)	2016		2016		Costs		Amount
Fine paid to the state	$	-	$	300	$	-	$	300
Customer bill credit paid		-		400		-		400
Charge for disallowed capital (1)		283		689		-		689
Disallowed revenue for pipeline safety
expenses (2)		129		129		32		161
CPUC estimated cost of other remedies (3)		-		-		-		50
Total Penalty Decision fines and remedies	$	412	$	1,518	$	32	$	1,600

(1)The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs.  On December 1, 2016, the CPUC approved a final phase two decision in the Utility’s 2015 GT&S rate case which allocates $689 million of the $850 million penalty to capital expenditures.

(2)GT&S revenues have been reduced for these unrecovered expenses. The remaining charges will be recognized in the first quarter of 2017.

(3)In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision.  This table does not reflect the Utility’s remedy-related costs already incurred or the Utility’s estimated future remedy-related costs.

Capital Expenditures Relating to Pipeline Safety Enhancement Plan

The CPUC has authorized the Utility to collect $766 million for recovery of PSEP capital costs.  As of December 31, 2016, the Utility has spent $1.35 billion on PSEP-related capital costs, of which $665 million was expensed in previous years for costs that are expected to exceed the authorized amount.  The Utility expects the remaining PSEP work to continue beyond 2017.  The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected.

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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
	December 31		December 31,
(in millions)	2016		2015
Topock natural gas compressor station (1)	$	299	$	300
Hinkley natural gas compressor station (1)		135		140
Former manufactured gas plant sites owned by the Utility or third parties		285		271
Utility-owned generation facilities (other than fossil fuel-fired),   other facilities, and third-party disposal sites		131		164
Fossil fuel-fired generation facilities and sites		108		94
Total environmental remediation liability	$	958	$	969

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

The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the EPA under the federal Resource Conversation and Recovery Act as well as other state hazardous waste laws.  The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements.  The Utility assesses and monitors, on an ongoing basis, measures that may be necessary to comply with these laws and regulations and implements changes to its program as deemed appropriate.  The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability at December 31, 2016 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 implement final remediation plans 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.

At December 31, 2016the Utility expected to recover $671 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 Needles, California and is referred to below as the “Topock site.”  Another station is located near Hinkley, California and is referred to below as the “Hinkley site.”  The Utility is also required to take measures to abate the effects of the contamination on the environment.

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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 DTSC and the DOI.  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 conducted an additional environmental review of the proposed design and issued a draft environmental impact report for public comment in January 2017.  After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in mid-2017. After the Utility modifies its design in response to the final report, the Utility will seek approval to begin construction of the new in-situ treatment system in late 2017 or early 2018.

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.  In November 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.

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 Topockand Hinkley 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, financial condition and cash flows 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 $3.2 billion per nuclear incident and $2.6 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.

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 $3.2 billion for each insured loss.  In contrast, NEIL would treat all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share the $3.2 billion policy limit amount. 

In addition to the nuclear insurance the Utility maintains through theNEIL, the Utility also is a member of theEMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon.

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, 2016, the current maximum aggregate annual retrospective premium obligation for the Utility would be approximately $60 million.EMANI provides $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies.  If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $2 million, as of December 31, 2016.

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Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to $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.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.  In connection with the CPUC approved settlement agreement, on April 12, 2004, the Utility deposited approximately $1.7 billion into escrow for the payment of certain disputed claims, previously collected from customers through rates.  Generally, 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.

On October 13, 2016, the Utility received approval from the bankruptcy court to release the remaining cash held in escrow to unrestricted cash for use by the Utility.  The approval resulted in a $161 million reduction to the cash in escrow within the Restricted cash balance on the Consolidated Balance Sheets.

On September 2, 2016, the Utility’s settlement became effective resolving, among other matters, the Utility’s claim against the CAISO for $165 million, which includes receivables and interest. Additionally, the Utility agreed to release $66 million of cash from escrow to the California Power Exchange.  The settlement resulted in a $231 million reduction to the Disputed claims and customer refunds balance onthe Consolidated Balance Sheets.    

At December 31, 2016 and December 31, 2015, respectively, the Consolidated Balance Sheets reflected $236 million and $454 million in net claims within Disputed claims and customer refunds.  The cash held in escrow within Restricted cash was zero as of December 31, 2016 and $228 million as of December 31, 2015. The Utility is uncertain when or how the remaining net disputed claims liability will be resolved. 

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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, 2016:

	Power Purchase Agreements
	Renewable		Conventional				Natural		Nuclear
(in millions)	Energy		Energy		Other		Gas		Fuel		Total
2017	$	2,233	$	815	$	369	$	536	$	97	$	4,050
2018		2,108		716		284		169		93		3,370
2019		2,144		698		225		160		95		3,322
2020		2,139		677		179		148		130		3,273
2021		2,117		585		147		93		49		2,991
Thereafter		27,685		1,168		653		455		136		30,097
Total purchase
commitments	$	38,426	$	4,659	$	1,857	$	1,561	$	600	$	47,103

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.  As of December 31, 2016, renewable energy contracts expire at various dates between 2017 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, 2016, these power purchase agreements expire at various dates between 2017 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, 2016 and 2015, net capital leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $35 million and $54 million including accumulated amortization of $148 million and $147 million, respectively.  The present value of the future minimum lease payments due under these agreements included $17 million and $19 million in Current Liabilities and $18 million and $35 million in Noncurrent Liabilities on the Consolidated Balance Sheet, respectively.As of December 31, 2016, QF contracts in operationexpire at various dates between 2017and2028.  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 2016, $3.5 billion in 2015, and $3.6 billion in 2014.

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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 2017 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 $0.7 billion in 2016, $0.9 billion in 2015, and $1.4 billion in 2014.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between2017and2025and 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 $100 million in 2016, $128 million in 2015, and $105 million in 2014.

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 2017 and2052.  At December 31, 2016, the future minimum payments related to these commitments were as follows:

(in millions)	Operating Leases
2017	$	44
2018		41
2019		39
2020		39
2021		36
Thereafter		168
Total minimum lease payments	$	367

Payments for other commitments related to operating leases amounted to $43million in 2016, $41 million in 2015, and $42 million in 2014.  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
2016
PG&E CORPORATION
Operating revenues (1)	$	4,713	$	4,810	$	4,169	$	3,974
Operating income		1,041		640		401		95
Income tax provision (benefit)  (2)		160		70		12		(187)
Net income (3)		696		391		210		110
Income available for common shareholders		692		388		206		107
Comprehensive income		694		391		210		110
Net earnings per common share, basic		1.37		0.77		0.41		0.22
Net earnings per common share, diluted		1.36		0.77		0.41		0.22
Common stock price per share:
High		62.12		65.39		63.92		59.72
Low		58.04		60.82		56.62		51.29
UTILITY
Operating revenues (1)	$	4,714	$	4,809	$	4,169	$	3,975
Operating income		1,044		640		401		96
Income tax provision (benefit) (2)		169		73		13		(185)
Net income (3)		696		389		209		108
Income available for common stock		692		386		205		105
Comprehensive income		694		389		210		108
2015
PG&E CORPORATION
Operating revenues	$	4,167	$	4,550	$	4,217	$	3,899
Operating income		205		545		687		71
Income tax (benefit) provision (4)		(111)		67		110		(93)
Net income (5)		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(4)		(114)		72		115		(92)
Net income (5)		147		305		406		4
Income available for common stock		143		302		402		1
Comprehensive income		145		305		406		4

(1) In the third and fourth quarters of 2016, the Utility recorded an increase in base revenues as authorized by the CPUC in the 2015 GT&S rate case decision.

(2) In the first quarter of 2016, the Utility had an income tax benefit, primarily due to net loss before income taxes and various tax audit results.

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(3) In the first, second, and third quarters of 2016, the Utility recorded charges for disallowed capital spending of $87 million, $148 million, and $51 million, respectively, as a result of the Penalty Decision.  Additionally, in the second and fourth quarters of 2016, the Utility recorded charges of $190 million and $29 million for capital expenditures probable of disallowance related to the final decision in the 2015 GT&S rate case.  Also, in the first quarter of 2016 the Utility recorded a $350 million charge related to Butte Fire litigation.  In the second quarter of 2016, the Utility recorded $260 million for probable insurance recoveries in connection with recovery of losses related to the Butte fire.  In the fourth quarter of 2016, the Utility recorded a $400 million charge related to the Butte fire litigation and an insurance receivable of $365 million for probable insurance recoveries in connection with the Butte fire.  (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

(4)In the first quarter of 2015, the Utility had an income tax benefit, primarily due to the impact of the Penalty Decision.(See footnote (4) 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.

(5)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.)

147

MANAGEMENT’S REPORTON INTERNAL CONTROL OVERFINANCIAL REPORTING

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

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

Management assessed the effectiveness of internal control over financial reporting as of December 31, 2016, 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, 2016.

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, 2016, 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, 2016, 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, 2016, 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, 2016of the Company and the Utility and our report dated February 16, 2017 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 16, 2017

149

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, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, 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, 2016, 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 16, 2017 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 16, 2017

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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, 2016, 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 2016 Form 10-K 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, 2016, 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, 2016 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 2016 Form 10-K.Other information regarding directors will be included under the heading “Nominees for Directors of PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2017 Annual Meetings of Shareholders, which information is incorporated herein by reference.Information regarding compliance with Section 16 of the Exchange Act will be included under the heading “Section16(a) Beneficial Ownership Reporting Compliance” in the Joint Proxy Statement relating to the 2017 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 the Corporate Governance section of PG&E Corporation’s website (www.pgecorp.com/aboutus/corp_gov) and on the Utility’s website (www.pge.com/about/company,under the Corporate Governance tab): (1)the PG&E Corporation and the Utility’s code of conduct (which meets the definition of “code of ethics” of Item 406(b) of the SEC Regulation S-K) adopted by PG&E Corporation and the Utility and applicable to their directors and employees, including their respective Chief Executive Officer and Presidents, as the case may be, Chief Financial Officers, Controllers and other executive officers, (2)PG&E Corporation’s and the Utility’s respective 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 code of conduct adopted by PG&E Corporation and the Utility and that apply to their respective Chief Executive Officer and Presidents, as the case may be, Chief Financial Officers, or Controllers, PG&E Corporation and the Utility will post the amended code of ethics on their websites and will disclose any waivers to the code of conduct in a Current Report on Form8-K.

Procedures for Shareholder Recommendations of Nominees to the Boards of Directors

Other than as noted below, there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2016 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or Pacific Gas and Electric Company’s Boards of Directors.

On December 16, 2016, the Boards of Directors of PG&E Corporation and the Utility each amended the applicable company’s respective Bylaw provisions regarding a shareholder’s right to (1) notify the company of the shareholder’s intent to introduce director nominees and other matters from the floor of the annual meeting of shareholders (“floor proposals”) or (2) call a special meeting of shareholders at which directors could be nominated or other business could be transacted.

In relevant part, PG&E Corporation’s and the Utility’s amended Bylaws (1) require that any “advance notice” of floor proposals be received between 90 and 120 days prior to the anniversary of the prior year’s annual meeting (previously, the deadline was 45 days prior to the mailing date of the proxy materials for the prior year’s annual meeting),(2) expand the information that must be included in a shareholder’s “advance notice” of a floor proposal, including requiring additional information regarding financial interests and intentions of the shareholder, as well as additional information relating to any director nominees, and (3) result in other procedural clarifications.

The amendments to PG&E Corporation’s Bylaws also establish deadlines, information requirements, and other processes relating to any PG&E Corporation shareholder’s request for a special meeting of the shareholders, including meetings at which director nominees will be presented for vote.

Audit Committees and Audit Committee Financial Expert

Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial experts” as defined by the SEC will be included under the headings “Corporate Governance – Board Committee Duties – Audit Committees” and “Corporate Governance – Committee Membership, Independence, and Qualifications” in the Joint Proxy Statement relating to the 2017 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, will be included under the headings “Compensation Discussion and Analysis,” “Compensation Committee Report,”“Summary Compensation Table - 2016,” “Grants of Plan-Based Awards in 2016,” “Outstanding Equity Awards at Fiscal Year End - 2016,” “Option Exercises and Stock Vested During 2016,” “Pension Benefits – 2016,” “Non-Qualified Deferred Compensation – 2016,”“Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” and “Compensation of Non-Employee Directors – 2016 Director Compensation” in the Joint Proxy Statement relating to the 2017 Annual 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 will be includedunder the headings “Share Ownership Information – Security Ownership of Management” and “Share Ownership Information – Principal Shareholders” in the Joint Proxy Statement relating to the 2017 Annual Meetings of Shareholders, which information is incorporated herein by reference.

Equity Compensation Plan Information

The following table provides information as of December31, 2016 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	6,962,072	(1)	$	35.53	(2)	13,826,995	(3)
Equity compensation plans not approved by shareholders	-			-		-
Total equity compensation plans	6,962,072	(1)	$	35.53	(2)	13,826,995	(3)

(1) Includes 21,675 phantom stock units, 2,002,357 restricted stock units and 4,933,950 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 2014, reflects the actual payout percentage of 160%.  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, 2016.

(3) Represents the total number of shares available for issuance under all of PG&E Corporation’s equity compensation plans as of December 31, 2016. 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, will be includedunder the headings “Related Party Transactions” and“Corporate Governance – Board and Director General Independence and Qualifications” and “Corporate Governance – Committee Membership, Independence, and Qualifications” in the Joint Proxy Statement relating to the 2017 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, will be includedunder the heading “Information Regarding the Independent Auditor for PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2017 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, 2016, 2015, and 2014 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2016, 2015, and 2014 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Balance Sheets at December31, 2016 and 2015 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015, and 2014 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Equity for the Years Ended December31, 2016, 2015, and 2014 for PG&E Corporation.

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2016, 2015, and 2014 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, 2016 and 2015 and for the Years Ended December31, 2016, 2015, and 2014.

II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December31, 2016, 2015, and 2014.

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 December 16, 2016
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 dated April12, 2004 (File No.1-2348), Exhibit 3)
3.5	Bylaws of Pacific Gas and Electric Company amended as of December 16, 2016
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 Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2005 (File No. 1-2348), Exhibit4.1)
4.2	First Supplemental Indenture, dated as of March 13, 2007, relating to the issuance of $700,000,000 principal amount of Pacific Gas and Electric Company’s 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 issuance of $500,000,000 principal amount of Pacific Gas and Electric Company’s 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  issuance of $200,000,000 Pacific Gas and Electric Company’s 5.625% Senior Notes due November 30, 2017 and $400,000,000 of its 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 issuance of $600,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 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 issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 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	Seventh Supplemental Indenture, dated as of June11, 2009 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June11, 2009 (FileNo.1-2348), Exhibit4.1)

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4.9	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)
4.10	Ninth Supplemental Indenture, dated as of April 1, 2010, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January15, 2040 and $250,000,000 aggregate principal amount of its Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)
4.11	Tenth Supplemental Indenture, dated as of September 15, 2010, relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1)
4.12	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 its 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)
4.13	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)
4.14	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)
4.15	Sixteenth Supplemental Indenture, dated as of December 1, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1)
4.16	Seventeenth Supplemental Indenture, dated as of April 16, 2012, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.45% Senior Notes due April 15, 2042(incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.17	Eighteenth Supplemental Indenture, dated as of August 16, 2012, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.45% Senior Notes due August 15, 2022 and $350,000,000 aggregate principal amount of its 3.75% Senior Notes due August 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.18	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)
4.19	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)

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4.20	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)
4.21	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)
4.22	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)
4.23	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 dated June 12, 2015 (File No. 1-2348), Exhibit 4.1)
4.24	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 dated November 5, 2015 (File No. 1-2348), Exhibit 4.1)
4.25	Twenty-Seventh Supplemental Indenture, dated as of March 1, 2016, relating to the issuance of $600,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.95% Senior Notes due March 1, 2026 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 1, 2016 (File No. 1-2348), Exhibit 4.1)
4.26	Twenty-Eighth Supplemental Indenture, dated as of December 1, 2016, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 30, 2017 and $400,000,000 aggregate principal amount of its 4.00% Senior Notes due December 1, 2046 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2016 (File No. 1-2348), Exhibit 4.1)
4.27	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)
4.28	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)

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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		Term Loan Agreement, dated as of March 2, 2016, between Pacific Gas and Electric Company and The Bank of Tokyo-Mitsubishi UFJ, Ltd. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 2, 2016 (File No. 1-2348), Exhibit 10.1)
10.4		Settlement Agreement among the 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 dated December 22, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
10.5		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)
10.6	*	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)
10.7	*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2016 grant under the PG&E Corporation 2014 Long-Term Incentive Plan
10.8	*	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)
10.9	*	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)
10.10	*	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)
10.11	*	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)
10.12	*	Performance Share Agreement subject to financial goals between Anthony F. Earley, Jr. and PG&E Corporation for 2016 grant under the PG&E Corporation 2014 Long-Term Incentive Plan
10.13	*	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)

158

10.14	*	Performance Share Agreement subject to safety and customer affordability goals between Anthony F. Earley, Jr. and PG&E Corporation for 2016 grant under the PG&E Corporation 2014 Long-Term Incentive Plan
10.15	*	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)
10.16	*	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)
10.17	*	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)
10.18	*	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 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2015 (File No. 1-2609 and File No. 1-2348), Exhibit 10.16)
10.19	*	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 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2015 (File No. 1-2609 and File No. 1-2348), Exhibit 10.17)
10.20	*	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 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2015 (File No. 1-2609 and File No. 1-2348), Exhibit 10.18)
10.21	*	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)
10.22	*	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)
10.23	*	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)
10.24	*	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)
10.25	*	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)
10.26	*	Restricted Stock Unit Agreement between Dinyar Mistry and PG&E Corporation dated February 23, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.2)
10.27	*	Separation agreement between Pacific Gas and Electric Company and Greg Kiraly dated February 18, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.3)

159

10.28	*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and David Thomason dated May 24, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended June 30, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.2)
10.29	*	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and David S. Thomason dated August 8, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended September 30, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.1)
10.30	*	Performance Share Award Agreement subject to financial goals between David S. Thomason and PG&E Corporation dated August 8, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended September 30, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.2)
10.31	*	Performance Share Award Agreement subject to safety and customer affordability goals between David S. Thomason and PG&E Corporation dated August 8, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended September 30, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.3)
10.32	*	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Edward D. Halpin dated November 28, 2016
10.33	*	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)
10.34	*	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)
10.35	*	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)
10.36	*	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)
10.37	*	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)
10.38	*	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)
10.39	*	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 8-K dated February 16, 2016 (File No. 1-12609 and File No. 1-2348)
10.40	*	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)
10.41	*	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)

160

10.42	*	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)
10.43	*	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)
10.44	*	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)
10.45	*	Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2015 (File No. 1-12609 and File No. 1-2348), Exhibit 10.38)
10.46	*	Amendment to the Postretirement Life Insurance Plan of the Pacific Gas and Electric Company, effective February 16, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.4)
10.47	*	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)
10.48	*	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)
10.49	*	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)
10.50	*	PG&E Corporation 2014 Long-Term Incentive Plan effective May 12, 2014 and amended effective January 1, 2016 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2015 (File No. 1-12609 and File No. 1-2348), Exhibit 10.42)
10.51	*	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)
10.52	*	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)
10.53	*	Form of Restricted Stock Unit Agreement for 2016 grants to non-employee directors under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended June 30, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.1)
10.54	*	Form of Restricted Stock Unit Agreement for 2015 grants to non-employee 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)
10.55	*	Form of Restricted Stock Unit Agreement for 2016 grants under the PG&E Corporation 2014 Long-Term Incentive Plan
10.56	*	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)
10.57	*	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)

161

10.58	*	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)
10.59	*	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)
10.60	*	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 dated January6, 2005 (File No.1-12609 and File No.1-2348), Exhibit99.1)
10.61	*	Form of Performance Share Agreement subject to financial goals for 2016 grants under the PG&E Corporation 2014 Long-Term Incentive Plan
10.62	*	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)
10.63	*	Form of Performance Share Agreement subject to safety and customer affordability goals for 2016 grants under the PG&E Corporation 2014 Long-Term Incentive Plan
10.64	*	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)
10.65	*	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)
10.66	*	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)
10.67	*	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)
10.68	*	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)
10.69	*	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)
10.70	*	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)
10.71	*	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)
10.72	*	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)
10.73	*	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)
10.74	*	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)

162

10.75	*	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)
10.76	*	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
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.

163

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, 2016 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 16, 2017	Date:	February 16, 2017
			GEISHA J. WILLIAMS
			Geisha J. Williams
		By:	President, Electric
		Date:	February 16, 2017

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 President	February 16, 2017
Anthony F. Earley, Jr.	(PG&E Corporation)
NICKOLAS STAVROPOULOS	President, Gas	February 16, 2017
Nickolas Stavropoulos	(Pacific Gas and Electric Company)
GEISHA J. WILLIAMS	President, Electric	February 16, 2017
Geisha  J. Williams	(Pacific Gas and Electric Company)
B.Principal Financial Officers
JASON P. WELLS	Senior Vice President and Chief Financial Officer	February 16, 2017
Jason P. Wells	(PG&E Corporation)
DAVID S. THOMASON	Vice President, Chief Financial Officer, and Controller	February 16, 2017
David S. Thomason	(Pacific Gas and Electric Company)

164

	C. Principal Accounting Officer
	DAVID S. THOMASON	Vice President and Controller (PG&E Corporation)	February 16, 2017
	David S. Thomason	Vice President, Chief Financial Officer, and Controller
		(Pacific Gas and Electric Company)
	D.Directors
*	LEWIS CHEW	Director	February 16, 2017
	Lewis Chew
*	ANTHONY F. EARLEY, JR.	Director	February 16, 2017
	Anthony F. Earley, Jr.
*	FRED J. FOWLER	Director	February 16, 2017
	Fred J. Fowler
*	MARYELLEN C. HERRINGER	Director	February 16, 2017
	Maryellen C. Herringer
*	RICHARD C. KELLY	Director	February 16, 2017
	Richard C. Kelly
*	ROGER H. KIMMEL	Director	February 16, 2017
	Roger H. Kimmel
*	RICHARD A. MESERVE	Director	February 16, 2017
	Richard A. Meserve
*	FORREST E. MILLER	Director	February 16, 2017
	Forrest E. Miller
*	ERIC D. MULLINS	Director	February 16, 2017
	Eric D. Mullins
*	ROSENDO G. PARRA	Director	February 16, 2017
	Rosendo G. Parra
*	BARBARA L. RAMBO	Director	February 16, 2017
	Barbara L. Rambo
*	ANNE SHEN SMITH	Director	February 16, 2017
	Anne Shen Smith
*	NICKOLAS STAVROPOULOS	Director (Pacific Gas and Electric Company only)	February 16, 2017
	Nickolas Stavropoulos

165

*	BARRY LAWSON WILLIAMS	Director	February 16, 2017
	Barry Lawson Williams
*	GEISHA J.WILLIAMS	Director (Pacific Gas and Electric Company only)	February 16, 2017
	Geisha J. Williams
*By:	HYUN PARK		February 16, 2017
	HYUN PARK, Attorney-in-Fact

166

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, 2016 and 2015, and for each of the three years in the period ended December 31, 2016, and the Company's and the Utility’s internal control over financial reporting as of December 31, 2016, and have issued our reports thereon dated February 16, 2017; such consolidated financial statements and reports are included elsewhere 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 16, 201

167

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)		2016		2015		2014
Administrative service revenue	$	70	$	51	$	51
Operating expenses		(73)		(53)		(53)
Interest income		1		1		1
Interest expense		(10)		(10)		(14)
Other income (expense)		2		30		(1)
Equity in earnings of subsidiaries		1,388		852		1,413
Income before income taxes		1,378		871		1,397
Income tax benefit		15		3		39
Net income	$	1,393	$	874	$	1,436
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $1,
$0, and $10, at respective dates)	$	(2)	$	(1)	$	(14)
Net change in investments (net of taxes of $0, $12, and $17, at respective dates)		-		(17)		(25)
Total other comprehensive income (loss)		(2)		(18)		(39)
Comprehensive Income	$	1,391	$	856	$	1,397
Weighted Average Common Shares Outstanding, Basic		499		484		468
Weighted Average Common Shares Outstanding, Diluted		501		487		470
Net earnings per common share, basic	$	2.79	$	1.81	$	3.07
Net earnings per common share, diluted	$	2.78	$	1.79	$	3.06

168

PG&E CORPORATION

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

CONDENSED BALANCE SHEETS

	Balance at December31,
(in millions)	2016		2015
ASSETS
Current Assets
Cash and cash equivalents	$	106	$	64
Advances to affiliates		24		22
Income taxes receivable		25		24
Other		-		1
Total current assets		155		111
Noncurrent Assets
Equipment		2		2
Accumulated depreciation		(2)		(2)
Net equipment		-		-
Investments in subsidiaries		18,172		16,837
Other investments		133		130
Deferred income taxes		267		250
Total noncurrent assets		18,572		17,217
Total Assets	$	18,727	$	17,328
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable – other		7		3
Other		274		246
Total current liabilities		281		249
Noncurrent Liabilities
Long-term debt		348		348
Other		158		155
Total noncurrent liabilities		506		503
Common Shareholders’ Equity
Common stock		12,198		11,282
Reinvested earnings		5,751		5,301
Accumulated other comprehensive income (loss)		(9)		(7)
Total common shareholders’ equity		17,940		16,576
Total Liabilities and Shareholders’ Equity	$	18,727	$	17,328

169

PG&E CORPORATION

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

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2016		2015		2014
Cash Flows from Operating Activities:
Net income	$	1,393	$	874	$	1,436
Adjustments to reconcile net income to net cash provided by
operating activities:
Stock-based compensation amortization		74		66		65
Equity in earnings of subsidiaries		(1,388)		(852)		(1,413)
Deferred income taxes and tax credits-net		11		10		(72)
Noncurrent income taxes receivable/payable		-		-		5
Current income taxes receivable/payable		(1)		5		(16)
Other		(24)		(70)		43
Net cash provided by operating activities		65		33		48
Cash Flows From Investing Activities:
Investment in subsidiaries		(835)		(705)		(978)
Dividends received from subsidiaries (1)		911		716		716
Proceeds from tax equity investments		-		-		368
Net cash provided by (used in) investing activities		76		11		106
Cash Flows From Financing Activities:
Borrowings (repayments) under revolving credit facilities		-		-		(260)
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $3		-		-		347
Repayments of long-term debt		-		-		(350)
Common stock issued		822		780		802
Common stock dividends paid(2)		(921)		(856)		(828)
Net cash provided by (used in) financing activities		(99)		(76)		(289)
Net change in cash and cash equivalents		42		(32)		(135)
Cash and cash equivalents at January 1		64		96		231
Cash and cash equivalents at December 31	$	106	$	64	$	96
Supplemental disclosure of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(9)	$	(9)	$	(15)
Income taxes, net		(13)		-		1
Supplemental disclosure of noncash investing and financing activities
Noncash common stock issuances	$	20	$	21	$	21
Common stock dividends declared but not yet paid		248		224		217

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

(2)In January of 2016, PG&E Corporation paid a quarterly common stock dividend of $0.455 per share.
In April, July and October of 2016, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share.
In January, April, July, and October of 2015 and 2014, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

170

PG&E Corporation

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2016, 2015, and 2014

(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:
2016:
Allowance for uncollectible accounts (1)	$	54	$	50	$	-	$	46	$	58
2015:
Allowance for uncollectible accounts (1)	$	66	$	43	$	-	$	55	$	54
2014:
Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66

(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.

171

Pacific Gas and Electric Company

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2016, 2015, and 2014

(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:
2016:
Allowance for uncollectible accounts (1)	$	54	$	50	$	-	$	46	$	58
2015:
Allowance for uncollectible accounts (1)	$	66	$	43	$	-	$	55	$	54
2014:
Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66

(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.

172

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 December 16, 2016
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 dated April12, 2004 (File No.1-2348), Exhibit 3)
3.5	Bylaws of Pacific Gas and Electric Company amended as of December 16, 2016
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 Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2005 (File No. 1-2348), Exhibit4.1)
4.2	First Supplemental Indenture, dated as of March 13, 2007, relating to the issuance of $700,000,000 principal amount of Pacific Gas and Electric Company’s 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 issuance of $500,000,000 principal amount of Pacific Gas and Electric Company’s 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  issuance of $200,000,000 Pacific Gas and Electric Company’s 5.625% Senior Notes due November 30, 2017 and $400,000,000 of its 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 issuance of $600,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 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 issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 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	Seventh Supplemental Indenture, dated as of June11, 2009 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June11, 2009 (FileNo.1-2348), Exhibit4.1)

173

4.9	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)
4.10	Ninth Supplemental Indenture, dated as of April 1, 2010, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January15, 2040 and $250,000,000 aggregate principal amount of its Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)
4.11	Tenth Supplemental Indenture, dated as of September 15, 2010, relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1)
4.12	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 its 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)
4.13	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)
4.14	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)
4.15	Sixteenth Supplemental Indenture, dated as of December 1, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1)
4.16	Seventeenth Supplemental Indenture, dated as of April 16, 2012, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.45% Senior Notes due April 15, 2042(incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.17	Eighteenth Supplemental Indenture, dated as of August 16, 2012, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.45% Senior Notes due August 15, 2022 and $350,000,000 aggregate principal amount of its 3.75% Senior Notes due August 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.18	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)
4.19	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)

174

4.20	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)
4.21	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)
4.22	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)
4.23	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 dated June 12, 2015 (File No. 1-2348), Exhibit 4.1)
4.24	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 dated November 5, 2015 (File No. 1-2348), Exhibit 4.1)
4.25	Twenty-Seventh Supplemental Indenture, dated as of March 1, 2016, relating to the issuance of $600,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.95% Senior Notes due March 1, 2026 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 1, 2016 (File No. 1-2348), Exhibit 4.1)
4.26	Twenty-Eighth Supplemental Indenture, dated as of December 1, 2016, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 30, 2017 and $400,000,000 aggregate principal amount of its 4.00% Senior Notes due December 1, 2046 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2016 (File No. 1-2348), Exhibit 4.1)
4.27	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)
4.28	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)

175

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		Term Loan Agreement, dated as of March 2, 2016, between Pacific Gas and Electric Company and The Bank of Tokyo-Mitsubishi UFJ, Ltd. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 2, 2016 (File No. 1-2348), Exhibit 10.1)
10.4		Settlement Agreement among the 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 dated December 22, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
10.5		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)
10.6	*	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)
10.7	*	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2016 grant under the PG&E Corporation 2014 Long-Term Incentive Plan
10.8	*	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)
10.9	*	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)
10.10	*	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)
10.11	*	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)
10.12	*	Performance Share Agreement subject to financial goals between Anthony F. Earley, Jr. and PG&E Corporation for 2016 grant under the PG&E Corporation 2014 Long-Term Incentive Plan
10.13	*	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)

176

10.14	*	Performance Share Agreement subject to safety and customer affordability goals between Anthony F. Earley, Jr. and PG&E Corporation for 2016 grant under the PG&E Corporation 2014 Long-Term Incentive Plan
10.15	*	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)
10.16	*	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)
10.17	*	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)
10.18	*	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 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2015 (File No. 1-2609 and File No. 1-2348), Exhibit 10.16)
10.19	*	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 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2015 (File No. 1-2609 and File No. 1-2348), Exhibit 10.17)
10.20	*	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 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2015 (File No. 1-2609 and File No. 1-2348), Exhibit 10.18)
10.21	*	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)
10.22	*	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)
10.23	*	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)
10.24	*	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)
10.25	*	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)
10.26	*	Restricted Stock Unit Agreement between Dinyar Mistry and PG&E Corporation dated February 23, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.2)
10.27	*	Separation agreement between Pacific Gas and Electric Company and Greg Kiraly dated February 18, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.3)

177

10.28	*	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and David Thomason dated May 24, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended June 30, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.2)
10.29	*	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and David S. Thomason dated August 8, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended September 30, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.1)
10.30	*	Performance Share Award Agreement subject to financial goals between David S. Thomason and PG&E Corporation dated August 8, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended September 30, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.2)
10.31	*	Performance Share Award Agreement subject to safety and customer affordability goals between David S. Thomason and PG&E Corporation dated August 8, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended September 30, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.3)
10.32	*	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Edward D. Halpin dated November 28, 2016
10.33	*	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)
10.34	*	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)
10.35	*	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)
10.36	*	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)
10.37	*	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)
10.38	*	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)
10.39	*	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 8-K dated February 16, 2016 (File No. 1-12609 and File No. 1-2348)
10.40	*	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)
10.41	*	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)

178

10.42	*	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)
10.43	*	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)
10.44	*	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)
10.45	*	Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2015 (File No. 1-12609 and File No. 1-2348), Exhibit 10.38)
10.46	*	Amendment to the Postretirement Life Insurance Plan of the Pacific Gas and Electric Company, effective February 16, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.4)
10.47	*	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)
10.48	*	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)
10.49	*	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)
10.50	*	PG&E Corporation 2014 Long-Term Incentive Plan effective May 12, 2014 and amended effective January 1, 2016 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2015 (File No. 1-12609 and File No. 1-2348), Exhibit 10.42)
10.51	*	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)
10.52	*	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)
10.53	*	Form of Restricted Stock Unit Agreement for 2016 grants to non-employee directors under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended June 30, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit10.1)
10.54	*	Form of Restricted Stock Unit Agreement for 2015 grants to non-employee 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)
10.55	*	Form of Restricted Stock Unit Agreement for 2016 grants under the PG&E Corporation 2014 Long-Term Incentive Plan
10.56	*	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)
10.57	*	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)

179

10.58	*	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)
10.59	*	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)
10.60	*	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 dated January6, 2005 (File No.1-12609 and File No.1-2348), Exhibit99.1)
10.61	*	Form of Performance Share Agreement subject to financial goals for 2016 grants under the PG&E Corporation 2014 Long-Term Incentive Plan
10.62	*	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)
10.63	*	Form of Performance Share Agreement subject to safety and customer affordability goals for 2016 grants under the PG&E Corporation 2014 Long-Term Incentive Plan
10.64	*	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)
10.65	*	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)
10.66	*	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)
10.67	*	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)
10.68	*	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)
10.69	*	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)
10.70	*	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)
10.71	*	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)
10.72	*	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)
10.73	*	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)
10.74	*	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)

180

10.75	*	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)
10.76	*	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
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.

181

EX-3.3

EXHIBIT 3.3

Bylaws

of

PG&E Corporation

amended as of December 16, 2016

Article I.SHAREHOLDERS.

1.Place of Meeting.  All meetings of the shareholders shall be held at the office of the Corporation in the City and County of San Francisco, State of California, or at such other place, within or without the State of California, as may be designated by the Board of Directors.

A meeting of the shareholders may be conducted, in whole or in part, by electronic transmission by and to the Corporation or by electronic video screen communication if: (a) the Corporation implements reasonable measures to provide shareholders (in person or by proxy) a reasonable opportunity to participate in the meeting and to vote on matters submitted to the shareholders, and (b) the Corporation maintains a record of the vote or action and any shareholder votes or other shareholder actions taken at the meeting by means of electronic transmission to the Corporation or electronic video screen communication.

Any request by the Corporation to a shareholder under Section 20(b) of the California Corporations Code for consent to conduct a meeting of shareholders by electronic transmission must include a notice that, absent consent of the shareholder, the meeting will be held at a physical location.

2.Annual Meetings.  The annual meeting of shareholders shall be held each year on a date and at a time designated by the Board of Directors.

Written notice of the annual meeting shall be given not less than ten (or, if sent by third-class mail, thirty) nor more than sixty days prior to the date of the meeting to each shareholder entitled to vote thereat.  The notice shall state the place (if any), date, and hour of such meeting, the means of electronic transmission by and to the Corporation or electronic video screen communication (if any) by which shareholders may participate in that meeting, and those matters which the Board, at the time of mailing, intends to present for action by the shareholders.

Notice of any meeting of the shareholders shall be given by mail, electronic transmission, or other written communication to each holder of record of the stock entitled to vote thereat, at his address, as it appears on the books of the Corporation.

For purposes of this Section 2 only, "electronic transmission" from the Corporation means a communication (a) delivered by (i) facsimile telecommunication or electronic mail when directed to the facsimile number or electronic mail address, respectively, for that shareholder on record with the Corporation, (ii) posting on an electronic message board or network which the Corporation has designated for those communications, together with a separate notice to the recipient of the posting, which transmission shall be validly delivered upon the later of the posting or delivery of the separate notice thereof, or (iii) other means of electronic communication, (b) to a shareholder who has provided an unrevoked consent to the use of those means of transmission for such communications, and (c) that creates a record that is capable of retention, retrieval, and review, and that may thereafter be rendered into clearly legible tangible form.  In addition, the consent to an electronic transmission by the Corporation to an individual shareholder shall be preceded by or include a clear written statement to the shareholder as to: (a) any right of the recipient to have the record provided or made available on paper or in non-electronic form, (b) whether the consent applies only to that transmission, to specified categories of communications, or to all communications from the Corporation, and (c) the procedures the recipient must use to withdraw consent.

At an annual meeting of shareholders, only such business shall be conducted as shall have been properly brought before the annual meeting.  To be properly brought before an annual meeting, business must be (a) specified in the notice of the annual meeting (or any supplement thereto) given by or at the direction of the Board, or (b) otherwise properly brought before the annual meeting by a shareholder.  Notwithstanding anything in these Bylaws to the contrary, no business shall be conducted at an annual meeting except in accordance with the procedures set forth in this Section 2 and Article I, Section 3 of these Bylaws.

For business to be properly brought before an annual meeting by a shareholder, including the nomination of any person (other than a person nominated by or at the direction of the Board) for election to the Board, the shareholder must have given timely and proper written notice to the Corporate Secretary of the Corporation pursuant to this Section 2 or Article I, Section 3 of these Bylaws.

Other than director nominations pursuant to Article I, Section 3 of these Bylaws, to be timely, the shareholder's written notice must be received at the principal executive office of the Corporation not more than 120 days and not less than ninety days before the anniversary date of the prior year's annual meeting of shareholders; provided, however, that if the annual meeting to which the shareholder's written notice relates is to be held on a date that differs by more than thirty days from the date of the last annual meeting of shareholders, the shareholder's written notice to be timely must be so received not later than the close of business on the tenth day following the date on which public disclosure of the date of the annual meeting is made or given to shareholders.  Any shareholder's written notice that is delivered after the close of business (5:00 p.m. local time) will be considered received on the following business day.  As used in these Bylaws, "public disclosure" shall include disclosure in a press release or in a document publicly filed by the Corporation with the United States Securities and Exchange Commission (SEC) pursuant to Section 13, 14, or 15(d) of the Securities Exchange Act of 1934 (and its successors) (the "Exchange Act") and the rules and regulations promulgated thereunder.

To be proper, the shareholder's written notice must set forth as to each matter the shareholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (b) the text of the proposal or business to be brought before the annual meeting (including the text of any resolutions proposed for consideration, and in the event that such business includes a proposal to amend these Bylaws, the language of the proposed amendment), (c) the name and address of the shareholder as they appear on the Corporation's books and the name and address of any of its Associated Persons (defined below), (d) the class and number of shares of the Corporation that are beneficially owned or held of record by the shareholder or any of its Associated Persons, and a description of all Disclosable Interests (defined below) (i) held by the shareholder or any of its Associated Persons or (ii) to which any of them is a party, (e) a description of all agreements, arrangements, or understandings between or among (i) such shareholder, (ii) any Associated Person, and/or (iii) any other person or persons (naming such person or persons), in each case relating to the business to be brought before the annual meeting or pursuant to which such business is to be proposed by such shareholder, (f) any material interest of the shareholder or Associated Parties in such business, and (g) other such information concerning the shareholder, any of its Associated Persons, and such item of business as would be required under the rules of the SEC in a proxy statement soliciting proxies in support of the item of business proposed to be brought before the annual meeting; provided, however, that the disclosures required by this Section 2 shall not include any disclosures with respect to any broker, dealer, commercial bank, trust company, or similar nominee solely as a result of such entity being the shareholder directed to prepare and submit the notice required by these Bylaws on behalf of a beneficial owner or beneficial owners.

In addition, other than director nominations pursuant to Article I, Section 3 of these Bylaws, if the shareholder's written notice relates to the nomination at the annual meeting of any person for election to the Board, such notice to be proper must also set forth (a) the name, age, business address, and residence address of each person to be so nominated, (b) the principal occupation or employment of each such person, (c) the number of shares of capital stock of the Corporation beneficially owned by each such person and any and all Disclosable Interests held by each such person to which each such person is a party, (d) a description of all agreements, arrangements, or understandings (including compensation) between or among (i) such shareholder, (ii) each nominee, (iii) any Associated Person, and/or (iv) any other person or persons (naming such person or persons), in each case relating to the nomination or pursuant to which the nomination or nominations are to be made by such shareholder and/or relating to the candidacy or service of the nominee as a director of the Corporation, (e) a representation that the shareholder is a holder of record of stock of the Corporation entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to propose such nomination, (f) a representation as to whether the shareholder or the beneficial owner, if any, intends or is part of a group that intends (i) to deliver a proxy statement and/or form of proxy to holders of at least the percentage of the Corporation's outstanding capital stock required to elect the nominee, or (ii) otherwise to solicit proxies from shareholders in support of such nomination, (g) such other information concerning each such person as would be required under the rules of the SEC in a proxy statement soliciting proxies for the election of such person as a director, and accompanied by a consent, signed by each such person, to serve as a director of the Corporation if elected, and (h) if any such nominee, the shareholder nominating the nominee, or any such Associated Person expresses an intention or recommendation that the Corporation enter into a strategic transaction, any material interest in such transaction of each such proposed nominee, shareholder, or Associated Person, including without limitation, any equity interests or any Disclosable Interests held by each such nominee, shareholder, or Associated Person in any other person, the value of which interests could reasonably be expected to be materially affected by such transaction.  In addition, such notice must contain a written and signed representation and agreement of each such nominee, pursuant to which such nominee represents and agrees that he or she (a) is not and will not become a party to any agreement, arrangement, or understanding with, and has not given any commitment or assurance to, any person or entity as to how such nominee, if elected as a director, will act or vote on any issue or question or that could reasonably be expected to limit or interfere with such nominee's ability to comply with his or her fiduciary duties under applicable law that has not been disclosed to the Corporation, (b) is not and will not become a party to any agreement, arrangement, or understanding with any person or entity other than the Corporation with respect to any direct or indirect compensation, reimbursement, or indemnification in connection with service or action as a director that has not been disclosed to the Corporation, and (c) if elected as a director, will comply with all of the Corporation's then existing corporate governance, conflict of interest, confidentiality, and stock ownership and trading policies, codes, and guidelines and any other Corporation policies, codes, and guidelines applicable to directors.  To be proper notice, the shareholder's notice also must include a written questionnaire completed by the proposed nominee with respect to the background and qualifications of such proposed nominee (which form of questionnaire shall be provided by the Corporate Secretary upon request).

The Corporation may require any proposed nominee to furnish such other information as it may reasonably require to determine (a) the eligibility of such proposed nominee to serve as a director of the Corporation, and (b) whether such nominee qualifies as an "independent director" or "audit committee financial expert" under applicable law, securities exchange rule or regulation, or any publicly disclosed corporate governance guideline or committee charter of the Corporation.

In addition, for a shareholder's written notice to the Corporate Secretary to be proper and timely, a shareholder providing notice of any business (including the nomination of any person for election to the Board) proposed to be made at any annual meeting shall further update and supplement such notice, if necessary, so that the information provided or required to be provided in such notice pursuant to this Section 2 shall be true and correct as of the record date for the meeting and as of the date that is ten business days prior to the meeting or any adjournment or postponement thereof.  Such update and supplement (or, if applicable, written confirmation that the information provided in such notice is still true and correct as of the applicable date) shall be delivered to, or mailed to and received by, the Corporate Secretary at the principal executive office of the Corporation no later than five business days after the record date for the meeting or, if practicable, any adjournment or postponement thereof and, if not practicable, on the first practicable date prior to the date to which the meeting has been adjourned or postponed (in the case of the update and supplement required to be made as of ten business days prior to the meeting or any adjournment or postponement thereof).  A shareholder, in his or her initial written notice of any business to the Corporate Secretary, shall confirm his or her intention to update and supplement such notice as required herein.

Nothing in these Bylaws shall be deemed to affect any rights of a shareholder to request inclusion of proposals in the Corporation's proxy statement pursuant to Rule 14-8 under the Exchange Act.  Notwithstanding anything in these Bylaws to the contrary, except for proposals properly and timely made in accordance with Rule 14a-8 under the Exchange Act and included in the notice of annual meeting given by or at the direction of the Board, no business shall be conducted at any annual meeting except in accordance with the procedures set forth in this Section 2 and Article I, Section 3 of these Bylaws.

As used in this Section 2, "Associated Person" shall mean (a) the beneficial owner or beneficial owners on whose behalf the written notice of business proposed to be brought before the annual meeting is made, if different from the shareholder proposing such business, and (b) each "affiliate" or "associate" (each within the meaning of Rule 12b-2 under the Exchange Act for purposes of these Bylaws) of each such shareholder or beneficial owner.

As used in this Section 2, "Disclosable Interest" shall mean any agreement, arrangement, or understanding (including but not limited to any derivatives, swaps, long or short positions, options, warrants, convertible securities, stock appreciation or similar rights, hedging transactions, and borrowed or loaned shares that are held or have been entered into, directly or indirectly, by or on behalf of such shareholder, the nominee proposed by such shareholder, as applicable, or any such Associated Person), the effect or intent of which is to mitigate loss to, manage the risk or benefit of share price changes for, provide the opportunity to profit from share price changes to, or maintain, increase, or decrease the voting power of, such shareholder, proposed nominee, as applicable, or any such Associated Person, with respect to shares of stock of the Corporation; provided, however, that Disclosable Interests shall not include any such disclosures with respect to any broker, dealer, commercial bank, trust company, or similar nominee solely as a result of such entity being the shareholder directed to prepare and submit the notice required by these Bylaws on behalf of a beneficial owner or beneficial owners.

3.Nominations of Directors Included in the Corporation's Proxy Materials.

(a)Inclusion of Shareholder Nominee in Proxy Statement.  Subject to the provisions of this Section 3, if expressly requested in the relevant Nomination Notice (as defined in Section 3(d) below), the Corporation shall include in its proxy statement for any annual meeting of shareholders (but not at any special meeting of shareholders): (i) the name of any person nominated for election (the "Shareholder Nominee"), which shall also be included on the Corporation's form of proxy and ballot, by any Eligible Shareholder (as defined in Section 3(c)(i) below) or group of up to 20 Eligible Shareholders that, as determined by the Board of Directors or its designee acting in good faith, has (individually and collectively, in the case of a group) satisfied all applicable conditions and complied with all applicable procedures set forth in this Section 3 (such Eligible Shareholder or group of Eligible Shareholders being a "Nominating Shareholder"); (ii) disclosure about the Shareholder Nominee and the Nominating Shareholder required under the rules of the Securities and Exchange Commission or other applicable law to be included in the proxy statement; (iii) any statement included by the Nominating Shareholder in the Nomination Notice for inclusion in the proxy statement in support of the Shareholder Nominee's election to the Board of Directors (subject, without limitation, to Section 3(e)(ii), provided that such statement does not exceed 500 words; and (iv) any other information that the Corporation or the Board of Directors determines, in their discretion, to include in the proxy statement relating to the nomination of the Shareholder Nominee, including, without limitation, any statement in opposition to the nomination and any of the information provided pursuant to this Section 3.

(b)Maximum Number of Shareholder Nominees.

(i)The Corporation shall not be required to include in the proxy statement for an annual meeting of shareholders more Shareholder Nominees than that number of directors constituting 20 percent of the total number of directors of the Corporation on the last day on which a Nomination Notice may be submitted pursuant to this Section 3 (rounded down to the nearest whole number), but, in any event, not fewer than two (the "Maximum Number").  The Maximum Number for a particular annual meeting shall be reduced by: (1) Shareholder Nominees whose nominations are subsequently withdrawn and (2) Shareholder Nominees whom the Board of Directors itself decides to nominate for election at such annual meeting. In the event that one or more vacancies for any reason occurs on the Board of Directors after the deadline set forth in Section 3(d) but before the date of the annual meeting of shareholders and the Board of Directors resolves to reduce the size of the Board in connection therewith, the Maximum Number shall be calculated based on the number of directors in office as so reduced.

(ii)If the number of Shareholder Nominees pursuant to this Section 3 for any annual meeting of shareholders exceeds the Maximum Number, then, promptly upon notice from the Corporation, each Nominating Shareholder will select one Shareholder Nominee for inclusion in the proxy statement until the Maximum Number is reached, going in order of the amount (largest to smallest) of shares of the Corporation's common stock that each Nominating Shareholder disclosed as owned in its Nomination Notice, with the process repeated if the Maximum Number is not reached after each Nominating Shareholder has selected one Shareholder Nominee. If, after the deadline for submitting a Nomination Notice as set forth in Article I, Section 2(d), a Nominating Shareholder becomes ineligible or withdraws its nomination, or a Shareholder Nominee becomes ineligible or unwilling to serve on the Board of Directors, whether before or after the mailing of the definitive proxy statement, then the Corporation: (1) shall not be required to include in its proxy statement or on any ballot or form of proxy the Shareholder Nominee or any successor or replacement nominee proposed by the Nominating Shareholder or by any other Nominating Shareholder and (2) may otherwise communicate to its shareholders, including without limitation by amending or supplementing its proxy statement or ballot or form of proxy, that the Shareholder Nominee will not be included as a Shareholder Nominee in the proxy statement or on any ballot or form of proxy and will not be voted on at the annual meeting of shareholders.

(c)Eligibility of Nominating Shareholder.

(i)An "Eligible Shareholder" is a person who has either (1) been a record holder of the shares of common stock of the Corporation used to satisfy the eligibility requirements in this Section 3(c) continuously for the three-year period specified in subsection (c)(ii) of this Section 3 below or (2) provides to the Corporate Secretary of the Corporation, within the time period referred to in Section 3(d), evidence of continuous ownership of such shares for such three-year period from one or more securities intermediaries in a form that the Board of Directors or its designee, acting in good faith, determines acceptable.

(ii)An Eligible Shareholder or group of up to 20 Eligible Shareholders may submit a nomination in accordance with this Section 3 only if the person or group (in the aggregate) has continuously owned at least the Minimum Number (as defined in Section 3(c)(iii) below) (as adjusted for any stock splits, reverse stock splits, stock dividends or similar events) of shares of the Corporation's common stock throughout the three-year period preceding and including the date of submission of the Nomination Notice, and continues to own at least the Minimum Number of shares through the date of the annual meeting of shareholders. The following shall be treated as one Eligible Shareholder if such Eligible Shareholder shall provide together with the Nomination Notice documentation satisfactory to the Board of Directors or its designee, acting in good faith, that demonstrates compliance with the following criteria: (1) funds under common management and investment control; (2) funds under common management and funded primarily by the same employer; or (3) a "family of investment companies" or a "group of investment companies" (each as defined in the Investment Company Act of 1940, as amended). For the avoidance of doubt, in the event of a nomination by a Nominating Shareholder that includes more than one Eligible Shareholder, any and all requirements and obligations for a given Eligible Shareholder or, except as the context otherwise makes clear, the Nominating Shareholder that are set forth in this Section 3, including the minimum holding period, shall apply to each member of such group; provided, however, that the Minimum Number shall apply to the aggregate ownership of the group of Eligible Shareholders constituting the Nominating Shareholder.  Should any Eligible Shareholder withdraw from a group of Eligible Shareholders constituting a Nominating Shareholder at any time prior to the annual meeting of shareholders, the Nominating Shareholder shall be deemed to own only the shares held by the remaining Eligible Shareholders. As used in this Section 3, any reference to a "group" or "group of Eligible Shareholders" refers to any Nominating Shareholder that consists of more than one Eligible Shareholder and to all the Eligible Shareholders that make up such Nominating Shareholder.

(iii)The "Minimum Number" of shares of the Corporation's common stock means 3 percent of the number of outstanding shares of common stock of the Corporation as of the most recent date for which such amount is given in any filing by the Corporation with the Securities and Exchange Commission prior to the submission of the Nomination Notice.

(iv)For purposes of this Section 3, an Eligible Shareholder "owns" only those outstanding shares of the Corporation's common stock as to which such Eligible Shareholder possesses both: (1) the full voting and investment rights pertaining to such shares and (2) the full economic interest in (including the opportunity for profit from and the risk of loss on) such shares; provided that the number of shares calculated in accordance with clauses (1) and (2) shall not include any shares (x) sold by such Eligible Shareholder or any of its affiliates in any transaction that has not been settled or closed, (y) borrowed by such Eligible Shareholder or any of its affiliates for any purpose or purchased by such Eligible Shareholder or any of its affiliates pursuant to an agreement to resell, or (z) subject to any option, warrant, forward contract, swap, contract of sale, or other derivative or similar agreement entered into by such Eligible Shareholder or any of its affiliates, whether any such instrument or agreement is to be settled with shares or with cash based on the notional amount or value of outstanding capital stock of the Corporation, in any such case which instrument or agreement has, or is intended to have, the purpose or effect of: (A) reducing in any manner, to any extent or at any time in the future, such Eligible Shareholder's or any of its affiliates' full right to vote or direct the voting of any such shares, and/or (B) hedging, offsetting, or altering to any degree any gain or loss arising from the full economic ownership of such shares by such Eligible Shareholder or any of its affiliates. An Eligible Shareholder "owns" shares held in the name of a nominee or other intermediary so long as the Eligible Shareholder retains the right to instruct how the shares are voted with respect to the election of directors and possesses the full economic interest in the shares. An Eligible Shareholder's ownership of shares shall be deemed to continue during any period in which the Eligible Shareholder has delegated any voting power by means of a proxy, power of attorney, or other similar instrument or arrangement that is revocable at any time by the Eligible Shareholder.  An Eligible Shareholder's ownership of shares shall be deemed to continue during any period in which the Eligible Shareholder has loaned such shares, provided that the Eligible Shareholder has the power to recall such loaned shares on not more than five business days' notice. The terms "owned," "owning," and other variations of the word "own" shall have correlative meanings.  Whether outstanding shares of the Corporation are "owned" for these purposes shall be determined by the Board of Directors or its designee acting in good faith.  For purposes of this Section 3(c)(iv), the term "affiliate" or "affiliates" shall have the meaning ascribed thereto under the General Rules and Regulations under the Securities Exchange Act of 1934, as amended ("Exchange Act").

(v)No Eligible Shareholder shall be permitted to be in more than one group constituting a Nominating Shareholder, and if any Eligible Shareholder appears as a member of more than one group, such Eligible Shareholder shall be deemed to be a member of only the group that has the largest ownership position as reflected in the Nomination Notice.

(d)Nomination Notice.  To nominate a Shareholder Nominee pursuant to this Section 3, the Nominating Shareholder must submit to the Corporate Secretary of the Corporation all of the following information and documents in a form that the Board of Directors or its designee, acting in good faith, determines acceptable (collectively, the "Nomination Notice"), not less than 120 days nor more than 150 days prior to the anniversary of the date that the Corporation mailed its proxy statement for the prior year's annual meeting of shareholders; provided, however, that if (and only if) the annual meeting of shareholders is not scheduled to be held within a period that commences 30 days before the first anniversary date of the preceding year's annual meeting of shareholders and ends 30 days after the first anniversary date of the preceding year's annual meeting of shareholders (an annual meeting date outside such period being referred to herein as an "Other Meeting Date"), the Nomination Notice shall be given in the manner provided herein by the later of the close of business on the date that is 180 days prior to such Other Meeting Date or the tenth day following the date such Other Meeting Date is first publicly announced or disclosed (in no event shall the adjournment or postponement of an annual meeting, or the announcement thereof, commence a new time period (or extend any time period) for the giving of the Nomination Notice):

(i)one or more written statements from the record holder of the shares (and from each intermediary through which the shares are or have been held during the requisite three-year holding period) verifying that, as of a date within seven (7) calendar days prior to the date of the Nomination Notice, the Nominating Shareholder owns, and has continuously owned for the preceding three (3) years, the Minimum Number of shares, and the Nominating Shareholder's agreement to provide, within five (5) business days after the record date for the annual meeting, written statements from the record holder and intermediaries verifying the Nominating Shareholder's continuous ownership of the Minimum Number of shares through the record date;

(ii)an agreement to provide immediate notice if the Nominating Shareholder ceases to own the Minimum Number of shares at any time prior to the date of the annual meeting;

(iii)a copy of the Schedule 14N (or any successor form) relating to the Shareholder Nominee, completed and filed with the Securities and Exchange Commission by the Nominating Shareholder as applicable, in accordance with Securities and Exchange Commission rules;

(iv)the written consent of each Shareholder Nominee to being named in the Corporation's proxy statement, form of proxy, and ballot as a nominee and to serving as a director if elected;

(v)a written notice of the nomination of such Shareholder Nominee that includes the following additional information, agreements, representations, and warranties by the Nominating Shareholder (including, for the avoidance of doubt, each group member in the case of a Nominating Shareholder consisting of a group of Eligible Shareholders): (1) the information that would be required to be set forth in a shareholder's notice of nomination pursuant to Article I, Section 2 of these Bylaws; (2) the details of any relationship that existed within the past three years and that would have been described pursuant to Item 6(e) of Schedule 14N (or any successor item) if it existed on the date of submission of the Schedule 14N; (3) a representation and warranty that the Nominating Shareholder did not acquire, and is not holding, securities of the Corporation for the purpose or with the effect of influencing or changing control of the Corporation; (4) a representation and warranty that the Nominating Shareholder has not nominated and will not nominate for election to the Board of Directors at the annual meeting any person other than such Nominating Shareholder's Shareholder Nominee(s); (5) a representation and warranty that the Nominating Shareholder has not engaged in and will not engage in a "solicitation" within the meaning of Rule 14a-1(l) under the Exchange Act (without reference to the exception in Section 14a-1(l)(2)(iv)) with respect to the annual meeting, other than with respect to such Nominating Shareholder's Shareholder Nominee(s) or any nominee of the Board of Directors); (6) a representation and warranty that the Nominating Shareholder will not use any proxy card other than the Corporation's proxy card in soliciting shareholders in connection with the election of a Shareholder Nominee at the annual meeting; (7) a representation and warranty that the Shareholder Nominee's candidacy or, if elected, Board membership would not violate applicable state or federal law or the rules of any stock exchange on which the Corporation's securities are traded (the "Stock Exchange Rules"); (8) a representation and warranty that the Shareholder Nominee: (A) does not have any direct or indirect relationship with the Corporation that will cause the Shareholder Nominee to be deemed not independent pursuant to the Corporation's Corporate Governance Guidelines and director independence standards and otherwise qualifies as independent under the Corporation's Corporate Governance Guidelines, director independence standards, and the Stock Exchange Rules; (B) meets the audit committee and compensation committee independence requirements under the Stock Exchange Rules; (C) is a "non-employee director" for the purposes of Rule 16b-3 under the Exchange Act (or any successor rule); (D) is an "outside director" for the purposes of Section 162(m) of the Internal Revenue Code (or any successor provision); (E) is not and has not been subject to any event specified in Rule 506(d)(1) of Regulation D (or any successor rule) under the Securities Act of 1933 or Item 401(f) of Regulation S-K (or any successor rule) under the Exchange Act, without reference to whether the event is material to an evaluation of the ability or integrity of the Shareholder Nominee; and (F) meets the director qualifications set forth in the Corporation's Corporate Governance Guidelines; (9) a representation and warranty that the Nominating Shareholder satisfies the eligibility requirements set forth in Section 3(c); (10) a representation and warranty that the Nominating Shareholder will continue to satisfy the eligibility requirements described in Section 3(c) through the date of the annual meeting; (11) details of any position of the Shareholder Nominee as an officer or director of any competitor (that is, any entity that produces products or provides services that compete with or are alternatives to the principal products produced or services provided by the Corporation or its affiliates) of the Corporation, within the three years preceding the submission of the Nomination Notice; (12) if desired, a statement for inclusion in the proxy statement in support of the Shareholder Nominee's election to the Board of Directors, provided that such statement shall not exceed 500 words and shall fully comply with Section 14 of the Exchange Act and the rules and regulations thereunder; and (13) in the case of a nomination by a Nominating Shareholder comprised of a group, the designation by all Eligible Shareholders in such group of one Eligible Shareholder that is authorized to act on behalf of the Nominating Shareholder with respect to matters relating to the nomination, including withdrawal of the nomination;

(vi)an executed agreement pursuant to which the Nominating Shareholder (including in the case of a group, each Eligible Shareholder in that group) agrees: (1) to comply with all applicable laws, rules, and regulations in connection with the nomination, solicitation, and election; (2) to file any written solicitation or other communication with the Corporation's shareholders relating to one or more of the Corporation's directors or director nominees or any Shareholder Nominee with the Securities and Exchange Commission, regardless of whether any such filing is required under any rule or regulation or whether any exemption from filing is available for such materials under any rule or regulation; (3) to assume all liability stemming from an action, suit, or proceeding concerning any actual or alleged legal or regulatory violation arising out of any communication by the Nominating Shareholder or the Shareholder Nominee nominated by such Nominating Shareholder with the Corporation, its shareholders, or any other person in connection with the nomination or election of directors, including, without limitation, the Nomination Notice; (4) to indemnify and hold harmless (jointly and severally with all other Eligible Shareholders, in the case of a group of Eligible Shareholders) the Corporation and each of its directors, officers, and employees individually against any liability, loss, damages, expenses, or other costs (including attorneys' fees) incurred in connection with any threatened or pending action, suit, or proceeding, whether legal, administrative, or investigative, against the Corporation or any of its directors, officers, or employees arising out of or relating to a failure or alleged failure of the Nominating Shareholder or Shareholder Nominee to comply with, or any breach or alleged breach of, its, or his or her, as applicable, obligations, agreements, or representations under this Section 3; (5) in the event that any information included in the Nomination Notice, or any other communication by the Nominating Shareholder (including with respect to any Eligible Shareholder included in a group) with the Corporation, its shareholders, or any other person in connection with the nomination or election ceases to be true and accurate in all material respects (or due to a subsequent development omits a material fact necessary to make the statements made not misleading), to promptly (and in any event within 48 hours of discovering such misstatement or omission) notify the Corporation and any other recipient of such communication of the misstatement or omission in such previously provided information and of the information that is required to correct the misstatement or omission; and (6) in the event that the Nominating Shareholder (including any Eligible Shareholder included in a group) has failed to continue to satisfy the eligibility requirements described in Section 3(c), to promptly notify the Corporation; and

(vii)an executed agreement by the Shareholder Nominee: (1) to provide to the Corporation such other information, including completion of the Corporation's director nominee questionnaire, as the Board of Directors or its designee, acting in good faith, may request; (2) that the Shareholder Nominee has read and agrees, if elected to serve as a member of the Board of Directors, to adhere to the Corporation's Corporate Governance Guidelines, Code of Business Conduct and Ethics for Directors, and any other Corporation policies and guidelines applicable to directors; and (3) that the Shareholder Nominee is not and will not become a party to (A) any compensatory, payment or other financial agreement, arrangement, or understanding with any person or entity in connection with such person's nomination, candidacy, service, or action as director of the Corporation that has not been fully disclosed to the Corporation prior to or concurrently with the Nominating Shareholder's submission of the Nomination Notice, (B) any agreement, arrangement, or understanding with any person or entity as to how the Shareholder Nominee would vote or act on any issue or question as a director (a "Voting Commitment") that has not been fully disclosed to the Corporation prior to or concurrently with the Nominating Shareholder's submission of the Nomination Notice, or (C) any Voting Commitment that could limit or interfere with the Shareholder Nominee's ability to comply, if elected as a director of the Corporation, with his or her fiduciary duties under applicable law.

The information and documents required by this Section 3(d) shall be (i) provided with respect to and executed by each Eligible Shareholder in the group in the case of a Nominating Shareholder comprised of a group of Eligible Shareholders; and (ii) provided with respect to the persons specified in Instructions 1 and 2 to Items 6(c) and (d) of Schedule 14N (or any successor item) (x) in the case of a Nominating Shareholder that is an entity and (y) in the case of a Nominating Shareholder that is a group that includes one or more Eligible Shareholders that are entities.  The Nomination Notice shall be deemed submitted on the date on which all of the information and documents referred to in this Section 3(d) (other than such information and documents contemplated to be provided after the date the Nomination Notice is provided) have been delivered to or, if sent by mail, received by the Corporate Secretary of the Corporation.

(e)Exceptions.

(i)Notwithstanding anything to the contrary contained in this Section 3, the Corporation may omit from its proxy statement any Shareholder Nominee and any information concerning such Shareholder Nominee (including a Nominating Shareholder's statement in support) and no vote on such Shareholder Nominee will occur (notwithstanding that proxies in respect of such vote may have been received by the Corporation), and the Nominating Shareholder may not, after the last day on which a Nomination Notice would be timely, cure in any way any defect preventing the nomination of the Shareholder Nominee, if: (1) the Corporation receives a notice that a shareholder intends to nominate a candidate for director at the annual meeting pursuant to the advance notice requirements set forth in Article I, Section 2 of these Bylaws; (2) the Nominating Shareholder (or, in the case of a Nominating Shareholder consisting of a group of Eligible Shareholders, the Eligible Shareholder that is authorized to act on behalf of the Nominating Shareholder), or any qualified representative thereof, does not appear at the annual meeting to present the nomination submitted pursuant to this Section 3 or the Nominating Shareholder withdraws its nomination; (3) the Board of Directors or its designee, acting in good faith, determines that such Shareholder Nominee's nomination or election to the Board of Directors would result in the Corporation violating or failing to be in compliance with these Bylaws or the Corporation's Articles of Incorporation or any applicable law, rule, or regulation to which the Corporation is subject, including the Stock Exchange Rules; (4) the Shareholder Nominee has been, within the past three years, an officer or director of a competitor, as defined for purposes of Section 8 of the Clayton Antitrust Act of 1914, as amended; or (5) the Corporation is notified, or the Board of Directors or its designee acting in good faith determines, that a Nominating Shareholder has failed to continue to satisfy the eligibility requirements described in Section 3(c), any of the representations and warranties made in the Nomination Notice ceases to be true and accurate in all material respects (or omits a material fact necessary to make the statement made not misleading), the Shareholder Nominee becomes unwilling or unable to serve on the Board of Directors or any material violation or breach occurs of any of the obligations, agreements, representations, or warranties of the Nominating Shareholder or the Shareholder Nominee under this Section 3.

(ii)Notwithstanding anything to the contrary contained in this Section 3, the Corporation may omit from its proxy statement, or may supplement or correct, any information, including all or any portion of the statement in support of the Shareholder Nominee included in the Nomination Notice, if the Board of Directors or its designee in good faith determines that: (1) such information is not true in all material respects or omits a material statement necessary to make the statements made not misleading; (2) such information directly or indirectly impugns the character, integrity, or personal reputation of, or directly or indirectly makes charges concerning improper, illegal, or immoral conduct or associations, without factual foundation, with respect to, any individual, corporation, partnership, association, or other entity, organization, or governmental authority; (3) the inclusion of such information in the proxy statement would otherwise violate the Securities and Exchange Commission proxy rules or any other applicable law, rule, or regulation; or (4) the inclusion of such information in the proxy statement would impose a material risk of liability upon the Corporation.

The Corporation may solicit against, and include in the proxy statement its own statement relating to, any Shareholder Nominee.

4.Special Meetings.  Special meetings of the shareholders shall be called by the Corporate Secretary or an Assistant Corporate Secretary at any time on order of the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the Chief Executive Officer, or the President.  Special meetings of the shareholders shall also be called by the Corporate Secretary or an Assistant Corporate Secretary upon the written request of holders of shares entitled to cast not less than ten percent of the votes at the meeting measured as of the record date established pursuant to Article IV, Section 1 of these Bylaws.

Any such request shall be in writing, shall be delivered to the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the Chief Executive Officer, the President, or the Corporate Secretary, and shall state (a) the purposes of the meeting, (b) the business proposed to be transacted at such meeting and the reasons for conducting such business at the meeting, and (c) if such request is made by a shareholder, the text of the proposal or business to be brought before the meeting (including the text of any resolutions proposed for consideration, and in the event that such business includes a proposal to amend these Bylaws, the language of the proposed amendment).  In connection with any special meeting of the shareholders called in accordance with the provisions of this Section 4, upon written request in proper form sent pursuant to Section 601(c) of the California Corporations Code (or any successor provision) by the person or persons (other than the Board) calling such meeting, it shall be the duty of the Corporate Secretary, subject to the immediately succeeding sentence, to cause notice of such meeting to be given in accordance with Article I, Section 2, Paragraph 3 of these Bylaws as promptly as reasonably practicable and, in connection therewith, to establish the place and, subject to Section 601(c) of the California Corporations Code (or any successor provision), the date and hour of such meeting.

To be in proper form, any such shareholder request shall include the information required in Article I, Section 2 of these Bylaws.  Within five business days after receiving such a shareholder request, the Board shall determine whether such shareholder or shareholders have satisfied the requirements for calling a special meeting of the shareholders in accordance with the provisions of this Section 4, and shall notify the requesting party or parties of its finding.

In the event that a special meeting of shareholders is called pursuant to this Section 4 for the purpose of electing one or more directors, any shareholder entitled to vote in such election of directors may nominate a person or persons (as the case may be) for election to such position(s) as specified in the Corporation's notice of meeting, but only if the shareholder has given timely and proper written notice to the Corporate Secretary.

To be timely under this Section 4, the shareholder's written notice must be received by the close of business at the principal executive office of the Corporation not more than 120 days in advance of the date of such special meeting and not less than ninety days prior to the date of such special meeting or the tenth day following the date on which public disclosure of the date of the special meeting and of the nominees proposed by the Board to be elected at such meeting is first made or given to shareholders.  To be proper, the notice shall include the information required by the seventh through eleventh paragraphs of Article I, Section 2 of these Bylaws, as applied to the special meeting.  In no event shall any adjournment, recess, or postponement of a special meeting of shareholders or the public disclosure thereof commence a new time period (or extend any time period) for the giving of timely written notice for business to be properly brought before the special meeting by a shareholder as described in this Section 4.  Nominations of persons for election to the Board may be made at a special meeting of shareholders at which directors are to be elected pursuant to the Corporation's notice of meeting (a) by or at the direction of the Board or any duly authorized committee thereof, or (b) provided that the Board or any duly authorized committee thereof has determined that directors shall be elected at such meeting, by any shareholder of the Corporation who is a shareholder of record at the time the notice provided for in this Section 4 is delivered to the Corporate Secretary, who is entitled to vote at the meeting and upon such election, and who complies with the notice procedures set forth and referenced in this Section 4.

5.Determination of Proper Business.  Each of the Board of Directors, the Chairman of the Board, the lead director, and the presiding officer of any annual or special meeting of shareholders shall have the power to determine whether business was properly and timely proposed in accordance with the provisions of this Article I, and if any of them should determine that such business is not in compliance with Article I, the presiding officer of the annual or special meeting of shareholders shall have the authority to declare at the meeting that any such business was not properly and timely brought before the meeting and shall not be transacted.  Notwithstanding the foregoing provisions of this Article I, unless otherwise required by law, if the shareholder (or a qualified representative of the shareholder) does not appear at the annual or special meeting of shareholders to present a nomination or other proposed business (including any proposal included in the Corporation's proxy materials pursuant to and in compliance with Rule 14a-8 under the Exchange Act), such nomination shall be disregarded or such proposed business shall not be transacted, as the case may be, notwithstanding that proxies in respect of such vote may have been received by the Corporation.

6.Voting at Meetings.  At any meeting of the shareholders, each holder of record of stock shall be entitled to vote in person or by proxy.  The authority of proxies must be evidenced by a written document signed by the shareholder and must be delivered to the Corporate Secretary of the Corporation prior to the commencement of the meeting.

7.Shareholder Action by Written Consent.  Subject to Section 603 of the California Corporations Code, any action which, under any provision of the California Corporations Code, may be taken at any annual or special meeting of shareholders may be taken without a meeting and without prior notice if a consent in writing, setting forth the action so taken, shall be signed by the holders of outstanding shares having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted.

Any party seeking to solicit written consent from shareholders to take corporate action must deliver a notice to the Corporate Secretary of the Corporation which requests the Board of Directors to set a record date for determining shareholders entitled to give such consent.  Such written request must set forth as to each matter the party proposes for shareholder action by written consents (a) a brief description of the matter and (b) the class and number of shares of the Corporation that are beneficially owned by the requesting party.  Within ten days of receiving the request in the proper form, the Board shall set a record date for the taking of such action by written consent in accordance with California Corporations Code Section 701 and Article IV, Section 1 of these Bylaws.  If the Board fails to set a record date within such ten-day period, the record date for determining shareholders entitled to give the written consent for the matters specified in the notice shall be the day on which the first written consent is given in accordance with California Corporations Code Section 701(b)(2).

Each written consent delivered to the Corporation must set forth (a) the action sought to be taken, (b) the name and address of the shareholder as they appear on the Corporation's books, (c) the class and number of shares of the Corporation that are beneficially owned by the shareholder, (d) the name and address of the proxyholder authorized by the shareholder to give such written consent, if applicable, and (e) any material interest of the shareholder or proxyholder in the action sought to be taken.

Consents to corporate action shall be valid for a maximum of sixty days after the date of the earliest dated consent delivered to the Corporation.  Consents may be revoked by written notice (a) to the Corporation, (b) to the shareholder or shareholders soliciting consents or soliciting revocations in opposition to action by consent proposed by the Corporation (the "Soliciting Shareholders"), or (c) to a proxy solicitor or other agent designated by the Corporation or the Soliciting Shareholders.

Within three business days after receipt of the earliest dated consent solicited by the Soliciting Shareholders and delivered to the Corporation in the manner provided in California Corporations Code Section 603 or the determination by the Board that the Corporation should seek corporate action by written consent, as the case may be, the Corporate Secretary shall engage nationally recognized independent inspectors of elections for the purpose of performing a ministerial review of the validity of the consents and revocations.  The cost of retaining inspectors of election shall be borne by the Corporation.

Consents and revocations shall be delivered to the inspectors upon receipt by the Corporation, the Soliciting Shareholders or their proxy solicitors, or other designated agents.  As soon as consents and revocations are received, the inspectors shall review the consents and revocations and shall maintain a count of the number of valid and unrevoked consents.  The inspectors shall keep such count confidential and shall not reveal the count to the Corporation, the Soliciting Shareholder or their representatives, or any other entity.  As soon as practicable after the earlier of (a) sixty days after the date of the earliest dated consent delivered to the Corporation in the manner provided in California Corporations Code Section 603, or (b) a written request therefor by the Corporation or the Soliciting Shareholders (whichever is soliciting consents), notice of which request shall be given to the party opposing the solicitation of consents, if any, which request shall state that the Corporation or Soliciting Shareholders, as the case may be, have a good faith belief that the requisite number of valid and unrevoked consents to authorize or take the action specified in the consents has been received in accordance with these Bylaws, the inspectors shall issue a preliminary report to the Corporation and the Soliciting Shareholders stating:  (a) the number of valid consents, (b) the number of valid revocations, (c) the number of valid and unrevoked consents, (d) the number of invalid consents, (e) the number of invalid revocations, and (f) whether, based on their preliminary count, the requisite number of valid and unrevoked consents has been obtained to authorize or take the action specified in the consents.

Unless the Corporation and the Soliciting Shareholders shall agree to a shorter or longer period, the Corporation and the Soliciting Shareholders shall have forty-eight hours to review the consents and revocations and to advise the inspectors and the opposing party in writing as to whether they intend to challenge the preliminary report of the inspectors.  If no written notice of an intention to challenge the preliminary report is received within forty-eight hours after the inspectors' issuance of the preliminary report, the inspectors shall issue to the Corporation and the Soliciting Shareholders their final report containing the information from the inspectors' determination with respect to whether the requisite number of valid and unrevoked consents was obtained to authorize and take the action specified in the consents.  If the Corporation or the Soliciting Shareholders issue written notice of an intention to challenge the inspectors' preliminary report within forty-eight hours after the issuance of that report, a challenge session shall be scheduled by the inspectors as promptly as practicable.  A transcript of the challenge session shall be recorded by a certified court reporter.  Following completion of the challenge session, the inspectors shall as promptly as practicable issue their final report to the Soliciting Shareholders and the Corporation, which report shall contain the information included in the preliminary report, plus all changes in the vote totals as a result of the challenge and a certification of whether the requisite number of valid and unrevoked consents was obtained to authorize or take the action specified in the consents.  A copy of the final report of the inspectors shall be included in the book in which the proceedings of meetings of shareholders are recorded.

Unless the consent of all shareholders entitled to vote have been solicited in writing, the Corporation shall give prompt notice to the shareholders in accordance with California Corporations Code Section 603 of the results of any consent solicitation or the taking of the corporate action without a meeting and by less than unanimous written consent.

8.Qualified Representatives.  For purposes of this Article I, to be a "qualified representative" of the shareholder, a person must be a duly authorized officer, manager, or partner of such shareholder or must be authorized by a writing executed by such shareholder or an electronic transmission delivered by such shareholder to act for such shareholder as proxy at the applicable annual or special meeting of shareholders and such person must produce such writing or electronic transmission, or a reliable reproduction of the writing or electronic transmission, along with personal identification demonstrating the representative's identity, and in a format acceptable to the Corporation, at the applicable annual or special meeting.

Article II.DIRECTORS.

1.Number.  As stated in paragraph I of Article Third of this Corporation's Articles of Incorporation, the Board of Directors of this Corporation shall consist of such number of directors, not less than seven (7) nor more than thirteen (13).  The exact number of directors shall be thirteen (13) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board or the shareholders.

2.Powers.  In accordance with California Corporations Code Section 300, the Board of Directors shall exercise all the powers of the Corporation except those which are conferred upon or reserved to the shareholders by law, the Articles of Incorporation, or these Bylaws.

3.Committees.  The Board of Directors may, by resolution adopted by a majority of the authorized number of directors, designate and appoint one or more committees as the Board deems appropriate, each consisting of two or more directors, to serve at the pleasure of the Board; provided, however, that, as required by this Corporation's Articles of Incorporation, the members of the Executive Committee (should the Board designate an Executive Committee) must be appointed by the affirmative vote of two-thirds of the authorized number of directors.  Any such committee, including the Executive Committee, shall have the authority to act in the manner and to the extent provided in the resolution of the Board designating such committee and may have all the authority of the Board, except with respect to the matters set forth in California Corporations Code Section 311.

4.Time and Place of Directors' Meetings.  Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman of the Board, the Chief Executive Officer, or the President of the Corporation and contained in the notice of any such meeting.  Notice of meetings shall be delivered personally or sent by mail or electronic transmission at least seven days in advance unless otherwise authorized.

5.Special Meetings.  The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the Chief Executive Officer, the President, or any five directors may call a special meeting of the Board of Directors at any time.  Notice of the time and place of special meetings shall be given to each director by the Corporate Secretary.  Such notice shall be delivered personally or by telephone (or other system or technology designed to record and communicate messages, including facsimile, electronic mail, or other such means) to each director at least forty-eight hours in advance of such meeting, or sent by first-class mail or electronic transmission, postage prepaid, at least four days in advance of such meeting.

6.Quorum.  A quorum for the transaction of business at any meeting of the Board of Directors or any committee thereof shall consist of one-third of the authorized number of directors or committee members, or two, whichever is larger.

7.Action by Consent.  Any action required or permitted to be taken by the Board of Directors may be taken without a meeting if all directors individually or collectively consent in writing to such action and if the number of members of the Board serving at the time constitutes a quorum.  Such written consent or consents shall be filed with the minutes of the proceedings of the Board.

8.Meetings by Conference Telephone.  Any meeting, regular or special, of the Board of Directors or of any committee of the Board, may be held by conference telephone or similar communication equipment, provided that all directors participating in the meeting can hear one another.

9.Majority Voting.  In any uncontested election, nominees receiving the affirmative vote of a majority of the shares represented and voting at a duly held meeting at which a quorum is present (which shares voting affirmatively also constitute at least a majority of the required quorum) shall be elected.  In any election that is not an uncontested election, the nominees receiving the highest number of affirmative votes of the shares entitled to be voted for them, up to the number of directors to be elected by those shares, shall be elected; votes against a director and votes withheld shall have no legal effect.

For purposes of these Bylaws, "uncontested election" means an election of directors of the Corporation in which, at the expiration of the times fixed under Article I, Section 2 and Article I, Section 3 of these Bylaws requiring advance notification of director nominees, or for special meetings, at the time notice is given of the meeting at which the election is to occur, the number of nominees for election does not exceed the number of directors to be elected by the shareholders at that election.

If an incumbent director fails, in an uncontested election, to receive the vote required to be elected in accordance with this Section 9, then, unless the incumbent director has earlier resigned, the term of such incumbent director shall end on the date that is the earlier of (a) ninety (90) days after the date on which the voting results are determined pursuant to Section 707 of the California Corporations Code, or (b) the date on which the Board of Directors selects a person to fill the office held by that director in accordance with the procedures set forth in these Bylaws and Section 305 of the California Corporations Code.

Article III.OFFICERS.

1.Officers.  The officers of the Corporation shall be elected by the Board of Directors and include a President, a Corporate Secretary, a Treasurer, or other such officers as required by law.  The Board also may elect one or more Vice Presidents, Assistant Secretaries, Assistant Treasurers, and other such officers as may be appropriate, including the offices described below.  Any number of offices may be held by the same person.

2.Chairman (or Chair) of the Board.  The Chairman of the Board shall be a member of the Board of Directors and preside at all meetings of the shareholders, of the directors, and of the Executive Committee in the absence of the Chairman of that Committee.  The Chairman of the Board shall have such duties and responsibilities as may be prescribed by the Board or these Bylaws.  The Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character, and, in the absence or disability of the Chief Executive Officer, shall exercise the Chief Executive Officer's duties and responsibilities.

3.Vice Chairman (or Vice Chair) of the Board.  The Vice Chairman of the Board shall be a member of the Board of Directors and have such duties and responsibilities as may be prescribed by the Board, the Chairman of the Board, or these Bylaws.  In the absence of the Chairman of the Board, the Vice Chairman of the Board shall preside at all meetings of the Board and of the shareholders; and, in the absence of the Chairman of the Executive Committee and the Chairman of the Board, the Vice Chairman of the Board shall preside at all meetings of the Executive Committee.  The Vice Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character.

4.Chairman (or Chair) of the Executive Committee.  The Chairman of the Executive Committee shall be a member of the Board of Directors and preside at all meetings of the Executive Committee.  The Chairman of the Executive Committee shall aid and assist the other officers in the performance of their duties and shall have such other duties as may be prescribed by the Board or these Bylaws.

5.Chief Executive Officer.  The Chief Executive Officer shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or these Bylaws.  If there be no Chairman of the Board, the Chief Executive Officer shall also exercise the duties and responsibilities of that office.  The Chief Executive Officer shall have authority to sign on behalf of the Corporation agreements and instruments of every character.  In the absence or disability of the President, the Chief Executive Officer shall exercise the President's duties and responsibilities.

6.President.  The President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Chief Executive Officer, or these Bylaws.  If there be no Chief Executive Officer, the President shall also exercise the duties and responsibilities of that office.  The President shall have authority to sign on behalf of the Corporation agreements and instruments of every character.

7.Chief Financial Officer.  The Chief Financial Officer shall be responsible for the overall management of the financial affairs of the Corporation.  The Chief Financial Officer shall render a statement of the Corporation's financial condition and an account of all transactions whenever requested by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, or the President.

The Chief Financial Officer shall have such other duties as may from time to time be prescribed by the Board, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or these Bylaws.

8.General Counsel.  The General Counsel shall be responsible for handling on behalf of the Corporation all proceedings and matters of a legal nature.  The General Counsel shall render advice and legal counsel to the Board of Directors, officers, and employees of the Corporation, as necessary to the proper conduct of the business.  The General Counsel shall keep the management of the Corporation informed of all significant developments of a legal nature affecting the interests of the Corporation.

The General Counsel shall have such other duties as may from time to time be prescribed by the Board, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or these Bylaws.

9.Vice Presidents.  Each Vice President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or these Bylaws.  Each Vice President's authority to sign agreements and instruments on behalf of the Corporation shall be as prescribed by the Board.  The Board, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, or the President may confer a special title upon any Vice President.

10.Corporate Secretary.  The Corporate Secretary shall attend all meetings of the Board of Directors and the Executive Committee, and all meetings of the shareholders, and the Corporate Secretary shall record the minutes of all proceedings in books to be kept for that purpose.  The Corporate Secretary shall be responsible for maintaining a proper share register and stock transfer books for all classes of shares issued by the Corporation.  The Corporate Secretary shall give, or cause to be given, all notices required either by law or these Bylaws.  The Corporate Secretary shall keep the seal of the Corporation in safe custody, and shall affix the seal of the Corporation to any instrument requiring it and shall attest the same by the Corporate Secretary's signature.

The Corporate Secretary shall have such other duties as may be prescribed by the Board, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or these Bylaws.

The Assistant Corporate Secretaries shall perform such duties as may be assigned from time to time by the Board, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Corporate Secretary.  In the absence or disability of the Corporate Secretary, the Corporate Secretary's duties shall be performed by an Assistant Corporate Secretary.

11.Treasurer.  The Treasurer shall have custody of all moneys and funds of the Corporation, and shall cause to be kept full and accurate records of receipts and disbursements of the Corporation.  The Treasurer shall deposit all moneys and other valuables of the Corporation in the name and to the credit of the Corporation in such depositaries as may be designated by the Board of Directors or any employee of the Corporation designated by the Board.  The Treasurer shall disburse such funds of the Corporation as have been duly approved for disbursement.

The Treasurer shall perform such other duties as may from time to time be prescribed by the Board, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, the Chief Financial Officer, or these Bylaws.

The Assistant Treasurers shall perform such duties as may be assigned from time to time by the Board, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, the Chief Financial Officer, or the Treasurer.  In the absence or disability of the Treasurer, the Treasurer's duties shall be performed by an Assistant Treasurer.

12.Controller.  The Controller shall be responsible for maintaining the accounting records of the Corporation and for preparing necessary financial reports and statements, and the Controller shall properly account for all moneys and obligations due the Corporation and all properties, assets, and liabilities of the Corporation.  The Controller shall render to the officers such periodic reports covering the result of operations of the Corporation as may be required by them or any one of them.

The Controller shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, the Chief Financial Officer, or these Bylaws.  The Controller shall be the principal accounting officer of the Corporation, unless another individual shall be so designated by the Board.

Article IV.MISCELLANEOUS.

1.Record Date.  The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any meeting of shareholders, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise rights in respect to any change, conversion, or exchange of shares.  The record date so fixed shall be not more than sixty nor less than ten days prior to the date of such meeting nor more than sixty days prior to any other action for the purposes for which it is so fixed.  When a record date is so fixed, only shareholders of record on that date are entitled to notice of and to vote at the meeting, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise the rights, as the case may be.

2.Certificates; Direct Registration System.  Shares of the Corporation's capital stock may be certificated or uncertificated, as provided under California law.  Any certificates that are issued shall be signed in the name of the Corporation by the Chairman of the Board, the Vice Chairman of the Board, the President, or a Vice President and by the Chief Financial Officer, an Assistant Treasurer, the Corporate Secretary, or an Assistant Secretary, certifying the number of shares and the class or series of shares owned by the shareholder.  Any or all of the signatures on the certificate may be a facsimile.  In case any officer, Transfer Agent, or Registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, Transfer Agent, or Registrar before such certificate is issued, it may be issued by the Corporation with the same effect as if such person were an officer, Transfer Agent, or Registrar at the date of issue.  Shares of the Corporation's capital stock may also be evidenced by registration in the holder's name in uncertificated, book-entry form on the books of the Corporation in accordance with a direct registration system approved by the SEC and authorized by statute or by any securities exchange on which the stock of the Corporation may from time to time be traded.

Transfers of shares of stock of the Corporation shall be made by the Transfer Agent and Registrar on the books of the Corporation after receipt of a request with proper evidence of succession, assignment, or authority to transfer by the record holder of such stock, or by an attorney lawfully constituted in writing, and in the case of stock represented by a certificate, upon surrender of the certificate.  Subject to the foregoing, the Board of Directors shall have power and authority to make such rules and regulations as it shall deem necessary or appropriate concerning the issue, transfer, and registration of shares of stock of the Corporation, and to appoint and remove Transfer Agents and Registrars of transfers.

3.Lost Certificates.  Any person claiming a certificate of stock to be lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of that fact and verify the same in such manner as the Board of Directors may require, and shall, if the Board so requires, give the Corporation, its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form approved by counsel, and in amount and with such sureties as may be satisfactory to the Corporate Secretary of the Corporation, before a new certificate (or uncertificated shares in lieu of a new certificate) may be issued of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, mislaid, or destroyed.

Article V.AMENDMENTS.

1.Amendment by Shareholders.  Except as otherwise provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the affirmative vote of a majority of the outstanding shares entitled to vote at any regular or special meeting of the shareholders.

2.Amendment by Directors.  To the extent provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by resolution adopted by a majority of the members of the Board of Directors; provided, however, that amendments to Article II, Section 9 of these Bylaws, and any other Bylaw provision that implements a majority voting standard for director elections (excepting any amendments intended to conform those Bylaw provisions to changes in applicable laws) shall be amended by the shareholders of the Corporation as provided in Section 1 of this Article V.

EX-3.5

EXHIBIT 3.5

Bylaws

of

Pacific Gas and Electric Company

amended as of December 16, 2016

Article I.

SHAREHOLDERS.

1.Place of Meeting.  All meetings of the shareholders shall be held at the office of the Company in the City and County of San Francisco, State of California, or at such other place, within or without the State of California, as may be designated by the Board of Directors.

A meeting of the shareholders may be conducted, in whole or in part, by electronic transmission by and to the Company or by electronic video screen communication if: (a) the Company implements reasonable measures to provide shareholders (in person or by proxy) a reasonable opportunity to participate in the meeting and to vote on matters submitted to the shareholders, and (b) the Company maintains a record of the vote or action and any shareholder votes or other shareholder actions taken at the meeting by means of electronic transmission to the Company or electronic video screen communication.

Any request by the Company to a shareholder under Section 20(b) of the California Corporations Code for consent to conduct a meeting of shareholders by electronic transmission must include a notice that, absent consent of the shareholder, the meeting will be held at a physical location.

2.Annual Meetings.  The annual meeting of shareholders shall be held each year on a date and at a time designated by the Board of Directors.

Written notice of the annual meeting shall be given not less than ten (or, if sent by third‑class mail, thirty) nor more than sixty days prior to the date of the meeting to each shareholder entitled to vote thereat.  The notice shall state the place (if any), date, and hour of such meeting, the means of electronic transmission by and to the Company or electronic video screen communication (if any) by which shareholders may participate in that meeting, and those matters which the Board, at the time of mailing, intends to present for action by the shareholders.

Notice of any meeting of the shareholders shall be given by mail, electronic transmission, or other written communication to each holder of record of the stock entitled to vote thereat, at his address, as it appears on the books of the Company.

For purposes of this Section 2 only, "electronic transmission" from the Company means a communication (a) delivered by (i) facsimile telecommunication or electronic mail when directed to the facsimile number or electronic mail address, respectively, for that shareholder on record with the Company, (ii) posting on an electronic message board or network which the Company has designated for those communications, together with a separate notice to the recipient of the posting, which transmission shall be validly delivered upon the later of the posting or delivery of the separate notice thereof, or (iii) other means of electronic communication, (b) to a shareholder who has provided an unrevoked consent to the use of those means of transmission for such communications, and (c) that creates a record that is capable of retention, retrieval, and review, and that may thereafter be rendered into clearly legible tangible form.  In addition, the consent to an electronic transmission by the Company to an individual shareholder shall be preceded by or include a clear written statement to the shareholder as to: (a) any right of the recipient to have the record provided or made available on paper or in non-electronic form, (b) whether the consent applies only to that transmission, to specified categories of communications, or to all communications from the Company, and (c) the procedures the recipient must use to withdraw consent.

At an annual meeting of shareholders, only such business shall be conducted as shall have been properly brought before the annual meeting.  To be properly brought before an annual meeting, business must be (a) specified in the notice of the annual meeting (or any supplement thereto) given by or at the direction of the Board, or (b) otherwise properly brought before the annual meeting by a shareholder.  Notwithstanding anything in these Bylaws to the contrary, no business shall be conducted at an annual meeting except in accordance with the procedures set forth in this Section 2.

For business to be properly brought before an annual meeting by a shareholder, including the nomination of any person (other than a person nominated by or at the direction of the Board) for election to the Board, the shareholder must have given timely and proper written notice to the Corporate Secretary of the Company pursuant to this Section 2.

To be timely, the shareholder's written notice must be received at the principal executive office of the Company not more than 120 days and not less than ninety days before the anniversary date of the prior year's annual meeting of shareholders; provided, however, that if the annual meeting to which the shareholder's written notice relates is to be held on a date that differs by more than thirty days from the date of the last annual meeting of shareholders, the shareholder's written notice to be timely must be so received not later than the close of business on the tenth day following the date on which public disclosure of the date of the annual meeting is made or given to shareholders.  Any shareholder's written notice that is delivered after the close of business (5:00 p.m. local time) will be considered received on the following business day.  As used in these Bylaws, "public disclosure" shall include disclosure in a press release or in a document publicly filed by the Company with the United States Securities and Exchange Commission (SEC) pursuant to Section 13, 14, or 15(d) of the Securities Exchange Act of 1934 (and its successors) (the "Exchange Act") and the rules and regulations promulgated thereunder.

To be proper, the shareholder's written notice must set forth as to each matter the shareholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (b) the text of the proposal or business to be brought before the annual meeting (including the text of any resolutions proposed for consideration, and in the event that such business includes a proposal to amend these Bylaws, the language of the proposed amendment), (c) the name and address of the shareholder as they appear on the Company's books, and the name and address of any of its Associated Persons (defined below), (d) the class and number of shares of the Company that are beneficially owned or held of record by the shareholder or any of its Associated Persons, and a description of all Disclosable Interests (defined below) (i) held by the shareholder or any of its Associated Persons or (ii) to which any of them is a party, (e) a description of all agreements, arrangements, or understandings between or among (i) such shareholder, (ii) any Associated Person, and/or (iii) any other person or persons (naming such person or persons), in each case relating to the business to be brought before the annual meeting or pursuant to which such business is to be proposed by such shareholder, (f) any material interest of the shareholder or Associated Parties in such business, and (g) other such information concerning the shareholder, any of its Associated Persons, and such item of business as would be required under the rules of the SEC in a proxy statement soliciting proxies in support of the item of business proposed to be brought before the annual meeting; provided, however, that the disclosures required by this Section 2 shall not include any disclosures with respect to any broker, dealer, commercial bank, trust company, or similar nominee solely as a result of such entity being the shareholder directed to prepare and submit the notice required by these Bylaws on behalf of a beneficial owner or beneficial owners.

In addition, if the shareholder's written notice relates to the nomination at the annual meeting of any person for election to the Board, such notice to be proper must also set forth (a) the name, age, business address, and residence address of each person to be so nominated, (b) the principal occupation or employment of each such person, (c) the number of shares of capital stock of the Company beneficially owned by each such person and any and all Disclosable Interests held by each such person to which each such person is a party,(d) a description of all agreements, arrangements, or understandings (including compensation) between or among (i) such shareholder, (ii) each nominee, (iii) any Associated Person, and/or (iv) any other person or persons (naming such person or persons), in each case relating to the nomination or pursuant to which the nomination or nominations are to be made by such shareholder and/or relating to the candidacy or service of the nominee as a director of the Company, (e) a representation that the shareholder is a holder of record of stock of the Company entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to propose such nomination, (f) a representation as to whether the shareholder or the beneficial owner, if any, intends or is part of a group that intends (i) to deliver a proxy statement and/or form of proxy to holders of at least the percentage of the Company's outstanding capital stock required to elect the nominee, or (ii) otherwise to solicit proxies from shareholders in support of such nomination, (g) such other information concerning each such person as would be required under the rules of the SEC in a proxy statement soliciting proxies for the election of such person as a director, and accompanied by a consent, signed by each such person, to serve as a director of the Company if elected, and (h) if any such nominee, the shareholder nominating the nominee, or any such Associated Person expresses an intention or recommendation that the Company enter into a strategic transaction, any material interest in such transaction of each such proposed nominee, shareholder, or Associated Person, including without limitation, any equity interests or any Disclosable Interests held by each such nominee, shareholder, or Associated Person in any other person, the value of which interests could reasonably be expected to be materially affected by such transaction.  In addition, such notice must contain a written and signed representation and agreement of each such nominee, pursuant to which such nominee represents and agrees that he or she (a) is not and will not become a party to any agreement, arrangement or understanding with, and has not given any commitment or assurance to, any person or entity as to how such nominee, if elected as a director, will act or vote on any issue or question or that could reasonably be expected to limit or interfere with such nominee's ability to comply with his or her fiduciary duties under applicable law that has not been disclosed to the Company, (b) is not and will not become a party to any agreement, arrangement, or understanding with any person or entity other than the Company with respect to any direct or indirect compensation, reimbursement, or indemnification in connection with service or action as a director that has not been disclosed to the Company, and (c) if elected as a director, will comply with all of the Company's then existing corporate governance, conflict of interest, confidentiality, and stock ownership and trading policies, codes, and guidelines and any other Company policies, codes, and guidelines applicable to directors.  To be proper notice, the shareholder's notice also must include a written questionnaire completed by the proposed nominee with respect to the background and qualifications of such proposed nominee (which form of questionnaire shall be provided by the Corporate Secretary upon request).

The Company may require any proposed nominee to furnish such other information as it may reasonably require to determine (a) the eligibility of such proposed nominee to serve as a director of the Company, and (b) whether such nominee qualifies as an "independent director" or "audit committee financial expert" under applicable law, securities exchange rule or regulation, or any publicly disclosed corporate governance guideline or committee charter of the Company.

In addition, for a shareholder's written notice to the Corporate Secretary to be proper and timely, a shareholder providing notice of any business (including the nomination of any person for election to the Board) proposed to be made at any annual meeting shall further update and supplement such notice, if necessary, so that the information provided or required to be provided in such notice pursuant to this Section 2 shall be true and correct as of the record date for the meeting and as of the date that is ten business days prior to the meeting or any adjournment or postponement thereof.  Such update and supplement (or, if applicable, written confirmation that the information provided in such notice is still true and correct as of the applicable date) shall be delivered to, or mailed to and received by, the Corporate Secretary at the principal executive office of the Company no later than five business days after the record date for the meeting or, if practicable, any adjournment or postponement thereof and, if not practicable, on the first practicable date prior to the date to which the meeting has been adjourned or postponed (in the case of the update and supplement required to be made as of ten business days prior to the meeting or any adjournment or postponement thereof).  A shareholder, in his or her initial written notice of any business to the Corporate Secretary, shall confirm his or her intention to update and supplement such notice as required herein.

Nothing in these Bylaws shall be deemed to affect any rights of a shareholder to request inclusion of proposals in the Company's proxy statement pursuant to Rule 14-8 under the Exchange Act.  Notwithstanding anything in these Bylaws to the contrary, except for proposals properly and timely made in accordance with Rule 14a-8 under the Exchange Act and included in the notice of annual meeting given by or at the direction of the Board, no business shall be conducted at any annual meeting except in accordance with the procedures set forth in thisSection 2.

As used in this Section 2, "Associated Person" shall mean (a) the beneficial owner or beneficial owners on whose behalf the written notice of business proposed to be brought before the annual meeting is made, if different from the shareholder proposing such business, and (b) each "affiliate" or "associate" (each within the meaning of Rule 12b-2 under the Exchange Act for purposes of these Bylaws) of each such shareholder or beneficial owner.

As used in this Section 2, "Disclosable Interest" shall mean any agreement, arrangement, or understanding (including but not limited to any derivatives, swaps, long or short positions, options, warrants, convertible securities, stock appreciation or similar rights, hedging transactions, and borrowed or loaned shares that are held or have been entered into, directly or indirectly, by or on behalf of such shareholder, the nominee proposed by such shareholder, as applicable, or any such Associated Person), the effect or intent of which is to mitigate loss to, manage the risk or benefit of share price changes for, provide the opportunity to profit from share price changes to, or maintain, increase, or decrease the voting power of, such shareholder, proposed nominee, as applicable, or any such Associated Person, with respect to shares of stock of the Company; provided, however, that Disclosable Interests shall not include any such disclosures with respect to any broker, dealer, commercial bank, trust company, or similar nominee solely as a result of such entity being the shareholder directed to prepare and submit the notice required by these Bylaws on behalf of a beneficial owner or beneficial owners.

3.Special Meetings.  Special meetings of the shareholders shall be called by the Corporate Secretary or an Assistant Corporate Secretary at any time on order of the Board of Directors, the Chairman of the Board, the Vice Chairman, the Chairman of the Executive Committee, the Chief Executive Officer, or the President.  Special meetings of the shareholders shall also be called by the Corporate Secretary or an Assistant Corporate Secretary upon the written request of holders of shares entitled to cast not less than ten percent of the votes at the meeting.  Such request shall state the purposes of the meeting, and shall be delivered to the Chairman of the Board, the Vice Chairman, the Chairman of the Executive Committee, the Chief Executive Officer, the President or the Corporate Secretary.

A special meeting so requested shall be held on the date requested, but not less than thirty-five nor more than sixty days after the date of the original request.  Written notice of each special meeting of shareholders, stating the place, day, and hour of such meeting and the business proposed to be transacted thereat, shall be given in the manner stipulated in Article I, Section 2, Paragraph 3 of these Bylaws within twenty days after receipt of the written request.

4.Determination of Proper Business.  Each of the Board of Directors, the Chairman of the Board, the lead director, and the presiding officer of any annual or special meeting of shareholders shall have the power to determine whether business was properly and timely proposed in accordance with the provisions of this Article I, and if any of them should determine that such business is not in compliance with Article I, the presiding officer of the annual or special meeting of shareholders shall have the authority to declare at the meeting that any such business was not properly and timely brought before the meeting and shall not be transacted.  Notwithstanding the foregoing provisions of this Article I, unless otherwise required by law, if the shareholder (or a qualified representative of the shareholder) does not appear at the annual or special meeting of shareholders to present a nomination or other proposed business (including any proposal included in the Company's proxy materials pursuant to and in compliance with Rule 14a-8 under the Exchange Act), such nomination shall be disregarded or such proposed business shall not be transacted, as the case may be, notwithstanding that proxies in respect of such vote may have been received by the Company.

5.Voting at Meetings.  At any meeting of the shareholders, each holder of record of stock shall be entitled to vote in person or by proxy.  The authority of proxies must be evidenced by a written document signed by the shareholder and must be delivered to the Corporate Secretary of the Company prior to the commencement of the meeting.

6.No Cumulative Voting.  No shareholder of the Company shall be entitled to cumulate his or her voting power.

7.Qualified Representatives.  For purposes of this Article I, to be a "qualified representative" of the shareholder, a person must be a duly authorized officer, manager, or partner of such shareholder or must be authorized by a writing executed by such shareholder or an electronic transmission delivered by such shareholder to act for such shareholder as proxy at the applicable annual or special meeting of shareholders and such person must produce such writing or electronic transmission, or a reliable reproduction of the writing or electronic transmission, along with personal identification demonstrating the representative's identity, and in a format acceptable to the Company, at the applicable annual or special meeting.

Article II.

DIRECTORS.

1.Number.  The Board of Directors of this Company shall consist of such number of directors, not less than nine (9) nor more than seventeen (17).  The exact number of directors shall be fifteen (15) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board or the shareholders.

2.Powers.  In accordance with California Corporations Code Section 300, the Board of Directors shall exercise all the powers of the Company except those which are conferred upon or reserved to the shareholders by law, the Articles of Incorporation, or these Bylaws.

3.Committees.  The Board of Directors may, by resolution adopted by a majority of the authorized number of directors, designate and appoint one or more committees as the Board deems appropriate, each consisting of two or more directors, to serve at the pleasure of the Board; provided, however, that, as required by this Company's Articles of Incorporation, the members of the Executive Committee (should the Board designate an Executive Committee) must be appointed by the affirmative vote of two-thirds of the authorized number of directors.  Any such committee, including the Executive Committee, shall have the authority to act in the manner and to the extent provided in the resolution of the Board designating such committee and may have all the authority of the Board, except with respect to the matters set forth in California Corporations Code Section 311.

4.Time and Place of Directors' Meetings.  Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman, the Chief Executive Officer, or the President of the Company and contained in the notice of any such meeting.  Notice of meetings shall be delivered personally or sent by mail or electronic transmission at least seven days in advance unless otherwise authorized.

5.Special Meetings.  The Chairman of the Board, the Vice Chairman, the Chairman of the Executive Committee, the Chief Executive Officer, the President, or any five directors may call a special meeting of the Board of Directors at any time.  Notice of the time and place of special meetings shall be given to each director by the Corporate Secretary.  Such notice shall be delivered personally or by telephone (or other system or technology designed to record and communicate messages, including facsimile, electronic mail, or other such means) to each director at least forty-eight hours in advance of such meeting, or sent by first-class mail or electronic transmission, postage prepaid, at least four days in advance of such meeting.

6.Quorum.  A quorum for the transaction of business at any meeting of the Board of Directors or any committee thereof shall consist of one-third of the authorized number of directors or committee members, or two, whichever is larger.

7.Action by Consent.  Any action required or permitted to be taken by the Board of Directors may be taken without a meeting if all directors individually or collectively consent in writing to such action and if the number of members of the Board serving at the time constitutes a quorum.  Such written consent or consents shall be filed with the minutes of the proceedings of the Board.

8.Meetings by Conference Telephone.  Any meeting, regular or special, of the Board of Directors or of any committee of the Board, may be held by conference telephone or similar communication equipment, provided that all directors participating in the meeting can hear one another.

9.Majority Voting.  In any uncontested election, nominees receiving the affirmative vote of a majority of the shares represented and voting at a duly held meeting at which a quorum is present (which shares voting affirmatively also constitute at least a majority of the required quorum) shall be elected.  In any election that is not an uncontested election, the nominees receiving the highest number of affirmative votes of the shares entitled to be voted for them, up to the number of directors to be elected by those shares, shall be elected; votes against a director and votes withheld shall have no legal effect.

For purposes of these Bylaws, "uncontested election" means an election of directors of the Company in which, at the expiration of the times fixed under Article I, Section 2 of these Bylaws requiring advance notification of director nominees, or for special meetings, at the time notice is given of the meeting at which the election is to occur, the number of nominees for election does not exceed the number of directors to be elected by the shareholders at that election.

If an incumbent director fails, in an uncontested election, to receive the vote required to be elected in accordance with this Section 9, then, unless the incumbent director has earlier resigned, the term of such incumbent director shall end on the date that is the earlier of (a) ninety (90) days after the date on which the voting results are determined pursuant to Section 707 of the California Corporations Code, or (b) the date on which the Board of Directors selects a person to fill the office held by that director in accordance with the procedures set forth in these Bylaws and Section 305 of the California Corporations Code.

10.Certain Powers Reserved to the Shareholders.  So long as PG&E Corporation shall hold the majority of the outstanding shares of the Company, PG&E Corporation may require the written consent of the PG&E Corporation Chairman of the Board or the PG&E Corporation Chief Executive Officer to enter into and execute any transaction or type of transaction identified by the Board of Directors of PG&E Corporation as a "Designated Transaction."  For purposes of this Section 10, a Designated Transaction shall be any transaction or type of transaction identified in a duly adopted resolution of the Board of PG&E Corporation as requiring the written consent of the PG&E Corporation Chairman of the Board or the PG&E Corporation Chief Executive Officer pursuant to this Section 10.  Notwithstanding the foregoing, nothing in this Section 10 shall limit the power of the Company to enter into or execute any transaction or type of transaction prior to the receipt by the Corporate Secretary of the Company of the resolution designating such transaction or type of transaction as a Designated Transaction pursuant to this Section 10.

Article III.

OFFICERS.

1.Officers.  The officers of the Company shall be elected by the Board of Directors and include a President, a Corporate Secretary, a Treasurer, or other such officers as required by law.  The Board also may elect one or more Vice Presidents, Assistant Secretaries, Assistant Treasurers, and such other officers as may be appropriate, including the offices described below.  Any number of offices may be held by the same person.

2.Chairman (or Chair) of the Board.  The Chairman of the Board shall be a member of the Board of Directors and preside at all meetings of the shareholders, of the directors, and of the Executive Committee in the absence of the Chairman of that Committee.  The Chairman of the Board shall have such duties and responsibilities as may be prescribed by the Board or these Bylaws.  The Chairman of the Board shall have authority to sign on behalf of the Company agreements and instruments of every character, and in the absence or disability of the Chief Executive Officer, shall exercise the Chief Executive Officer's duties and responsibilities.

3.Vice Chairman (or Vice Chair).  The Vice Chairman may be, but is not required to be, a member of the Board of Directors and shall have such duties and responsibilities as may be prescribed by the Board, the Chairman of the Board, or these Bylaws.  If the Vice Chairman is a member of the Board, then (a) in the absence of the Chairman of the Board, the Vice Chairman shall preside at all meetings of the Board and of the shareholders; and (b) in the absence of the Chairman of the Executive Committee and the Chairman of the Board, the Vice Chairman shall preside at all meetings of the Executive Committee.  The Vice Chairman shall have authority to sign on behalf of the Company agreements and instruments of every character.

4.Chairman (or Chair) of the Executive Committee.  The Chairman of the Executive Committee shall be a member of the Board of Directors and preside at all meetings of the Executive Committee.  The Chairman of the Executive Committee shall aid and assist the other officers in the performance of their duties and shall have such other duties as may be prescribed by the Board or these Bylaws.

5.Chief Executive Officer.  The Chief Executive Officer shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or these Bylaws.  If there be no Chairman of the Board, the Chief Executive Officer shall also exercise the duties, responsibilities, authority, and powers of that office, including the authority to further delegate such duties, responsibilities, authority, and powers (subject to any specific delegation limitations established by the Board).  The Chief Executive Officer shall have authority to sign on behalf of the Company agreements and instruments of every character.  In the absence or disability of the President, the Chief Executive Officer shall exercise the President's duties and responsibilities.

6.President.  The President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Chief Executive Officer, or these Bylaws.  If there be no Chief Executive Officer, the President shall also exercise the duties, responsibilities, authority, and powers of that office, including the authority to further delegate such duties, responsibilities, authority, and powers (subject to any specific delegation limitations established by the Board).  The President shall have authority to sign on behalf of the Company agreements and instruments of every character.

If the Board elects more than one individual to simultaneously serve with the title of President, then all authority granted to the office of the President by these Bylaws (including the exercise of the duties, responsibilities, authority, and power of the Chief Executive Officer in the absence of such an officer) must be exercised and approved jointly by all individuals with the title of President, except if specified otherwise by the Board.  Notwithstanding the foregoing, if more than one individual simultaneously holds the title of President, then in the absence or disability of any individual President, the remaining President or Presidents may jointly exercise the powers granted by these Bylaws to the office of the President.  All other authority granted to the office of President by the Board (by resolution or otherwise, but not including authority granted pursuant to these Bylaws) may be exercised separately by each individual elected to the title of President, unless otherwise noted or otherwise required by law, regulation, or binding obligation of the Company.

7.Vice Presidents.  Each Vice President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman, the Chief Executive Officer, the President, or these Bylaws.  Each Vice President's authority to sign agreements and instruments on behalf of the Company shall be as prescribed by the Board.  The Board of this Company, the Chairman of the Board of this Company, the Vice Chairman of this Company, or the Chief Executive Officer of PG&E Corporation may confer a special title upon any Vice President.

8.Corporate Secretary.  The Corporate Secretary shall attend all meetings of the Board of Directors and the Executive Committee, and all meetings of the shareholders, and the Corporate Secretary shall record the minutes of all proceedings in books to be kept for that purpose.  The Corporate Secretary shall be responsible for maintaining a proper share register and stock transfer books for all classes of shares issued by the Company.  The Corporate Secretary shall give, or cause to be given, all notices required either by law or these Bylaws.  The Corporate Secretary shall keep the seal of the Company in safe custody, and shall affix the seal of the Company to any instrument requiring it and shall attest the same by the Corporate Secretary's signature.

The Corporate Secretary shall have such other duties as may be prescribed by the Board, the Chairman of the Board, the Vice Chairman, the Chief Executive Officer, the President, or these Bylaws.

The Assistant Corporate Secretaries shall perform such duties as may be assigned from time to time by the Board, the Chairman of the Board, the Vice Chairman, the Chief Executive Officer, the President, or the Corporate Secretary.  In the absence or disability of the Corporate Secretary, the Corporate Secretary's duties shall be performed by an Assistant Corporate Secretary.

9.Treasurer.  The Treasurer shall have custody of all moneys and funds of the Company, and shall cause to be kept full and accurate records of receipts and disbursements of the Company.  The Treasurer shall deposit all moneys and other valuables of the Company in the name and to the credit of the Company in such depositaries as may be designated by the Board of Directors or any employee of the Company designated by the Board.  The Treasurer shall disburse such funds of the Company as have been duly approved for disbursement.

The Treasurer shall perform such other duties as may from time to time be prescribed by the Board, the Chairman of the Board, the Vice Chairman, the Chief Executive Officer, the President, or these Bylaws.

The Assistant Treasurer shall perform such duties as may be assigned from time to time by the Board, the Chairman of the Board, the Vice Chairman, the Chief Executive Officer, the President, or the Treasurer.  In the absence or disability of the Treasurer, the Treasurer's duties shall be performed by an Assistant Treasurer.

10.General Counsel.  The General Counsel shall be responsible for handling on behalf of the Company all proceedings and matters of a legal nature.  The General Counsel shall render advice and legal counsel to the Board of Directors, officers, and employees of the Company, as necessary to the proper conduct of the business.  The General Counsel shall keep the management of the Company informed of all significant developments of a legal nature affecting the interests of the Company.

The General Counsel shall have such other duties as may from time to time be prescribed by the Board, the Chairman of the Board, the Vice Chairman, the Chief Executive Officer, the President, or these Bylaws.

11.Controller.  The Controller shall be responsible for maintaining the accounting records of the Company and for preparing necessary financial reports and statements, and the Controller shall properly account for all moneys and obligations due the Company and all properties, assets, and liabilities of the Company.  The Controller shall render to the officers such periodic reports covering the result of operations of the Company as may be required by them or any one of them.

The Controller shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman, the Chief Executive Officer, the President, or these Bylaws.  The Controller shall be the principal accounting officer of the Company, unless another individual shall be so designated by the Board.

Article IV.

MISCELLANEOUS.

1.Record Date.  The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any meeting of shareholders, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise rights in respect to any change, conversion, or exchange of shares.  The record date so fixed shall be not more than sixty nor less than ten days prior to the date of such meeting nor more than sixty days prior to any other action for the purposes for which it is so fixed.  When a record date is so fixed, only shareholders of record on that date are entitled to notice of and to vote at the meeting, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise the rights, as the case may be.

2.Certificates; Direct Registration System.  Shares of the Company's stock may be certificated or uncertificated, as provided under California law.  Any certificates that are issued shall be signed in the name of the Company by the Chairman of the Board, the Vice Chairman, the President, or a Vice President and by the Chief Financial Officer, an Assistant Treasurer, the Corporate Secretary, or an Assistant Secretary, certifying the number of shares and the class or series of shares owned by the shareholder.  Any or all of the signatures on the certificate may be a facsimile.  In case any officer, Transfer Agent, or Registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, Transfer Agent, or Registrar before such certificate is issued, it may be issued by the Company with the same effect as if such person were an officer, Transfer Agent, or Registrar at the date of issue.  Shares of the Company's capital stock may also be evidenced by registration in the holder's name in uncertificated, book-entry form on the books of the Company in accordance with a direct registration system approved by the SEC and authorized by statute or by any securities exchange on which the stock of the Company may from time to time be traded.

Transfers of shares of stock of the Company shall be made by the Transfer Agent and Registrar on the books of the Company only after receipt of a request with proper evidence of succession, assignment, or authority to transfer by the record holder of such stock, or by an attorney lawfully constituted in writing, and in the case of stock represented by a certificate, upon surrender of the certificate.  Subject to the foregoing, the Board of Directors shall have power and authority to make such rules and regulations as it shall deem necessary or appropriate concerning the issue, transfer, and registration of certificates for shares of stock of the Company, and to appoint and remove Transfer Agents and Registrars of transfers.

3.Lost Certificates.  Any person claiming a certificate of stock to be lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of that fact and verify the same in such manner as the Board of Directors may require, and shall, if the Board so requires, give the Company, its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form approved by counsel, and in amount and with such sureties as may be satisfactory to the Corporate Secretary of the Company, before a new certificate (or uncertificated shares in lieu of a new certificate) may be issued of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, mislaid, or destroyed.

Article V.

AMENDMENTS.

1.Amendment by Shareholders.  Except as otherwise provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the affirmative vote of a majority of the outstanding shares entitled to vote at any regular or special meeting of the shareholders.

2.Amendment by Directors.  To the extent provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by resolution adopted by a majority of the members of the Board of Directors; provided, however, that amendments to Article II, Sections 9 and 10 of these Bylaws, and any other Bylaw provision that implements a majority voting standard for director elections (excepting any amendments intended to conform those Bylaw provisions to changes in applicable laws) shall be amended by the shareholders of the Company as provided in Section 1 of this Article V.

EX-10.07

EXHIBIT 10.7

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT AWARD

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:March 1, 2016

Name of Recipient:ANTHONY F. EARLEY, JR.

Recipient's Participant ID:XXXXXXXX

Number of Restricted Stock Units:53,372

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 award, the attached Agreement, and a copy of the prospectus describing the LTIP and the Restricted Stock Units dated March 1, 2016, and any supplements to that prospectus.

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, 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 will 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 2012 Officer Severance Policy, this Agreement will govern. For purposes of this Agreement, employment with PG&E Corporation means 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 on the cover sheet, will vest in accordance with the below vesting schedule (the "Normal Vesting Schedule").        March 1, 2017 – one-third of the Restricted Stock Units        March 1, 2018 – one-third of the Restricted Stock Units        March 1, 2019 – one third of the Restricted Stock Units 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 will then be 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 will 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 will, 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 will vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such Retirement.  Your termination of employment will be considered Retirement if you are both age 55 or older on the date of termination (other than termination for cause) 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. For these purposes, "cause" means when PG&E Corporation, acting in good faith based upon information then known to it, determines that you have engaged in, committed, or are responsible for, (1) serious misconduct, gross negligence, theft, or fraud against PG&E Corporation and/or its affiliates, (2) refusal or unwillingness to perform your duties; (3) inappropriate conduct in violation of PG&E Corporation's equal employment opportunity policy; (4) conduct which reflects adversely upon, or making any remarks disparaging of, PG&E Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries; (5) insubordination; (6) any willful act that is likely to have the effect of injuring the reputation, business, or business relationships of PG&E Corporation or its subsidiaries or affiliates; (7) violation of any fiduciary duty; or (8) breach of any duty of loyalty.
Termination other than for Cause	Upon your termination (other than termination for cause, voluntary termination, Retirement, termination due to death or Disability, or termination in connection with a Change in Control) additional Restricted Stock Units will continue to vest (as if you continued to be employed by PG&E Corporation) such that the total number of vested Restricted Stock Units (including Restricted Stock Units, if any, that vested prior to the date of termination) will be equal to the greater of (1) the actual number of vested Restricted Stock Units or (2) the number determined by multiplying the total number of Restricted Stock Units subject to this Agreement by the number of your days of service with PG&E Corporation in the Normal Vesting Schedule (through the date of termination), divided by the potential number of days of service in the Normal Vesting Schedule.  All other unvested Restricted Stock Units will be cancelled upon such termination.  Vested Restricted Stock Units will continue to be settled and paid on the same time schedule and at the rate that would be normally applicable (absent your termination of employment) until the pro-rated amount (if any) is exhausted.
Death/Disability	In the event of your death or Disability while you are employed, all of your Restricted Stock Units will 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 will 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	If your employment is terminated (other than for cause, your voluntary termination, or your Retirement) (1) 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) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, then your Restricted Stock Units will 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 will 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, 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) will 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) will 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 has the sole discretion to determine whether termination of your employment was made in connection with a Change in Control
Delay	PG&E Corporation will 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 will 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 will 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 will 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.
Recoupment of Awards	Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

EX-10.12

EXHIBIT 10.12

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

PERFORMANCE SHARE AWARD - FINANCIAL

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

Date of Grant:March 1, 2016

Name of Recipient:ANTHONY F. EARLEY, JR.

Recipient's Participant ID:XXXXXXXX

Number of Performance Shares:70,582

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 award, the attached Agreement, and a copy of the prospectus describing the LTIP and the Performance Shares dated March 1, 2016, and any supplements to that Prospectus.

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, Pacific Gas and Electric Company, 245 Market Street, N2T, San Francisco, 94105.

Attachment

PG&E CORPORATION 2014

 LONG-TERM INCENTIVE PLAN

PERFORMANCE SHARE AGREEMENT- FINANCIAL

The LTIP and Other Agreements	This Agreement constitutes the entire understanding between you and PG&E Corporation regarding the Performance Shares, 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 will 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 2012 Officer Severance Policy, this Agreement will govern.  The LTIP provides the Committee with discretion to adjust the performance award formula. For purposes of this Agreement, employment with PG&E Corporation means employment with any member of the Participating Company Group.
Grant of Performance Shares	PG&E Corporation grants you the number of Performance Shares shown on the cover sheet of this Agreement (the "Performance Shares").  The Performance Shares are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Performance Shares Settlement in Shares/ Performance Goals	As long as you remain employed with PG&E Corporation, the Performance Shares will vest upon, and to the extent of, the Committee's certification of the extent to which performance goals have been attained for this award, which certification will occur on or after January 1 but before March 15 of the third year following the calendar year of grant specified in the cover sheet (the "Vesting Date").  Except as described below, all Performance Shares that have not vested will be cancelled upon termination of your employment. Vested Performance Shares will be settled in shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. The number of shares you are entitled to receive will be calculated by multiplying the number of vested Performance Shares by the "rounded payout percentage" determined as follows (except as set forth elsewhere in this Agreement), rounded to the nearest whole number:
	Upon the Vesting Date, PG&E Corporation's total shareholder return ("TSR") will be compared to the TSR of the fourteen other companies in PG&E Corporation's comparator group1 for the prior three calendar years, consisting of 2016, 2017, and 2018 (the "Performance Period").1  Subject to rounding considerations, if PG&E Corporation's TSR falls below the 25th percentile of the comparator group the payout percentage will be 0%; if PG&E Corporation's TSR is at the 25th percentile, the payout percentage will be 25%; if PG&E Corporation's TSR is at the 60th percentile, the payout percentage will be 100%; and if PG&E Corporation's TSR is in the 90th percentile or higher, the payout percentage will be 200%.  If PG&E Corporation's TSR performance is between the 25th percentile and the target, or between the target and the 90th percentile, the rounded payout percentage is determined by straight-line interpolation between the performance percentile associated with each comparator rank and between the rounded payouts associated with each performance percentile (including the 25th, 60th, and 90th percentiles) as shown in above table, rounded down to the nearest whole number.  The following table sets forth the rounded payout percentages for the TSR rankings that could be achieved by companies within the comparator group: Number of Companies inTotal (Excluding PG&E Corporation)   - 14                                                        Performance                  Rounded                                Rank                Percentile                        Payout                                  1                        100%                             200%                                   2                          93%                             200%                                                               90%                             200%                                   3                          86%                             186%                                  4                          79%                             162%                                  5                          71%                             138%                                  6                          64%                             114%                                                               60%                             100%                                   7                          57%                              94%                                  8                          50%                              79%                                  9                          43%                              63%                                10                          36%                              48%                                11                          29%                              33%                                                               25%                              25%                                 12                          21%                                0%                                 13                          14%                                0%                                 14                           7%                                 0% The payout percentage, if any, will be determined as soon as practicable following the date that the Committee (or a subcommittee of that Committee) or an equivalent body certifies the extent to which performance goals have been attained, pursuant to Section 10.5(a) of the LTIP.  PG&E Corporation will issue shares as soon as practicable after such determination, but no earlier than the Vesting Date, and not later than March 15 of the calendar year following completion of the Performance Period.
	(1) The current Performance Comparator Group consists of the following companies:  Ameren Corporation, American Electric Power, CMS Energy, Consolidated Edison, Inc., DTE Energy, Duke Energy, Edison International, Eversource Energy, NiSource, Inc., Pinnacle West Capital, SCANA Corp., Southern Company, Wisconsin Energy Corporation, and Xcel Energy, Inc.  PG&E Corporation reserves the right to change the companies comprising the comparator group and the resulting payout percentage table in accordance with the rules established by PG&E Corporation in connection with this award. (2) PG&E Corporation's TSR performance is measured by the value of stock price appreciation and dividends paid and reinvested, relative to companies in the Performance Comparator Group.  For these purposes, average share price will be measured by comparing the average per share closing price of PG&E Corporation common stock during the 20 trading days before the beginning and the end of the Performance Period.
Dividends	Each time that PG&E Corporation declares a dividend on its shares of common stock, an amount equal to the dividend multiplied by the number of Performance Shares granted to you by this Agreement will be accrued on your behalf.  If you receive a Performance Share settlement in accordance with the preceding paragraph, at that same time you also will receive a cash payment equal to the amount of any dividends accrued with respect to your Performance Shares over the Performance Period multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Voluntary Termination	If you terminate your employment with PG&E Corporation voluntarily before the Vesting Date (other than for Retirement), all of the Performance Shares will be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares will be forfeited.
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause before the Vesting Date, all of the Performance Shares will be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares will be forfeited. For these purposes, "cause" means when PG&E Corporation, acting in good faith based upon information then known to it, determines that you have engaged in, committed, or are responsible for, (1) serious misconduct, gross negligence, theft, or fraud against PG&E Corporation and/or its affiliates, (2) refusal or unwillingness to perform your duties; (3) inappropriate conduct in violation of PG&E Corporation's equal employment opportunity policy; (4) conduct which reflects adversely upon, or making any remarks disparaging of, PG&E Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries; (5) insubordination; (6) any willful act that is likely to have the effect of injuring the reputation, business, or business relationships of PG&E Corporation or its subsidiaries or affiliates; (7) violation of any fiduciary duty; or (8) breach of any duty of loyalty.

Termination other than for Cause	Upon your termination (other than termination for cause, voluntary termination, Retirement, termination due to death or Disability, or termination in connection with a Change in Control) the number of vested Performance Shares will equal the number of Performance Shares subject to this Agreement, multiplied by the number of your days of service with PG&E Corporation in the vesting period (through the date of termination), divided by the potential number of days of service in the vesting period.  All other outstanding Performance Shares  will be cancelled, and any associated accrued dividends forfeited, upon such termination. Your vested Performance Shares will be settled, if at all, as soon as practicable after the Vesting Date and no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applied to active employees. At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Retirement	If you retire before the Vesting Date, your outstanding Performance Shares will continue to vest as though your employment had continued and will be settled, if at all, as soon as practicable following the Vesting Date and no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applicable to active employees.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.   Your termination of employment will be considered a Retirement if you are age 55 or older on the date of termination (other than termination for cause) and if you were employed by PG&E Corporation for at least five consecutive years ending on the date of termination of your employment.
Death/Disability	If your employment terminates due to your death or disability before the Vesting Date, all of your Performance Shares will vest immediately and will be settled, if at all, as soon as practicable after the Vesting Date and no later than March 15 of the year following completion of the Performance Period based on the same payout percentage applied to active employees.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Termination Due to Disposition of Subsidiary	If your employment is terminated (other than for cause, your voluntary termination, or Retirement) (1) 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, or (2) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, then your outstanding Performance Shares will 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 Performance Shares subject to this Agreement. If the Acquiror assumes or continues PG&E Corporation's rights and obligations under this Agreement or substitutes a substantially equivalent award, TSR will be calculated by combining (a) the TSR of PG&E Corporation for the period from January 1 of the year of grant to the date of the Change in Control, and (b) the TSR of the Acquiror from the date of the Change in Control to the last day of the Performance Period.   The number of shares, if any, you are entitled to receive upon settlement of the assumed, continued or substituted Performance Share award will be determined based on the rounded payout percentage reflected in the table set forth above for the highest percentile TSR performance met or exceeded when calculated on that basis, and considering any adjustments to the comparator group. Settlement will occur as soon as practicable after the Vesting Date and no later than March 15 of the year following completion of the Performance Period.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares over the Performance Period multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any. If the Change in Control of PG&E Corporation occurs before the Vesting Date, and if this award is neither assumed nor continued by the Acquiror or if the Acquiror does not provide a substantially equivalent award in substitution for the Performance Shares subject to this Agreement, all of your outstanding Performance Shares will vest and become nonforfeitable on the date of the Change in Control.  Such vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date and no later than March 15 of the year following completion of the Performance Period.  The payout percentage, if any, will be based on TSR for the period from January 1 of the year of grant to the date of the Change in Control compared to the TSR of the other companies in PG&E Corporation's comparator group for the same period. At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares to the date of the Change in Control multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Termination In Connection with a Change in Control	If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within two years following the Change in Control, all of your outstanding Performance Shares (to the extent they did not previously vest upon failure of the Acquiror to assume or continue this award) will vest and become nonforfeitable on the date of termination of your employment. If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Performance Shares will vest in full and become nonforfeitable (including the portion that you would have otherwise forfeited based on the proration of vested Performance Shares through the date of termination of your employment) as of the date of the Change in Control. Your vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date and no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applied to active employees (determined consistent with the method decribed above under "Change in Control").  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any. PG&E Corporation has the sole discretion to determine whether termination of your employment was made in connection with a Change in Control.
Withholding Taxes	The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of your Performance Shares 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 Performance Shares 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." 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.

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.
Recoupment of Awards	Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

EX-10.14

EXHIBIT 10.14

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

PERFORMANCE SHARE AWARD – SAFETY AND AFFORDABILITY

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

Date of Grant:March 1, 2016

Name of Recipient:ANTHONY F. EARLEY, JR.

Recipient's Participant ID:XXXXXXXX

Number of Performance Shares:13,343

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 award, the attached Agreement, and a copy of the prospectus describing the LTIP and the Performance Shares dated March 1, 2016, and any supplements to that Prospectus.

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, Pacific Gas and Electric Company, 245 Market Street, N2T, San Francisco, 94105.

Attachment

PG&E CORPORATION 2014

 LONG-TERM INCENTIVE PLAN

PERFORMANCE SHARE AGREEMENT

SAFETY AND AFFORDABILITY

The LTIP and Other Agreements	This Agreement constitutes the entire understanding between you and PG&E Corporation regarding the Performance Shares, 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 will 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 2012 Officer Severance Policy, this Agreement will govern.  The LTIP provides the Committee with discretion to adjust the performance award formula. For purposes of this Agreement, employment with PG&E Corporation means employment with any member of the Participating Company Group.
Grant of Performance Shares	PG&E Corporation grants you the number of Performance Shares shown on the cover sheet of this Agreement (the "Performance Shares").  The Performance Shares are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Performance Shares Settlement in Shares/ Performance Goals	As long as you remain employed with PG&E Corporation, the Performance Shares will vest upon, and to the extent of, the Committee's certification of the extent to which performance goals have been attained for this award, which certification will occur on or after January 1 but before March 15 of the third year following the calendar year of grant specified in the cover sheet (the "Vesting Date").  Except as described below, all Performance Shares that have not vested will be cancelled upon termination of your employment. Vested Performance Shares will be settled in shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. The number of shares you are entitled to receive will be calculated by multiplying the number of vested Performance Shares by the "payout percentage" determined as follows (except as set forth elsewhere in this Agreement), rounded to the nearest whole number:
	Fifty percent of the Performance Shares have a safety performance goal and resulting safety payout percentage, and the other fifty percent of the Performance Shares have an affordability performance goal and resulting affordability payout percentage.  Subject to rounding considerations, in each case, if performance is below threshold,  the payout percentage will be 0%; if performance is at threshold, the payout percentage will be 25%; if performance is at target, the payout percentage will be 100%; and if performance is at or better than maximum, the payout percentage will be 200%.  The actual payout percentage for performance between threshold and maximum will be determined based on linear interpolation between the payout percentages for threshold and target, or target and maximum, as appropriate. The measures and goals are discussed in more detail below: Safety - At the end of 2018, PG&E Corporation's lost workday ("LWD") case rate ("LWD Rate") for that year will be measured as the number of LWD cases incurred per 200,000 hours worked during 2018. LWD cases will be measured in the same manner as for the 2016 Short-Term Incentive Plan, will include OSHA recordable incidents that result in loss of at least one workday, and will exclude fatalities.  Threshold performance is 0.247, target performance is 0.215, and maximum performance is 0.201. Affordability - PG&E Corporation's affordability performance will be measured as the reduction in standard rate case expense for unitized work and support operations and maintenance costs over the three calendar years prior to the normal Vesting Date (the "Performance Period"), as compared to escalated actual costs in these areas for 2014 escalated by two years (at 2.75 percent per year), as determined in the sole discretion of the Committee, in accordance with the terms adopted by the Committee at its February 16, 2016 meeting.  Threshold performance is $75 million, target performance is $100 million, and maximum performance is $200 million. The final payout percentages, if any, will be determined as soon as practicable following the date that the Committee (or a subcommittee of that Committee) or an equivalent body certifies the extent to which the performance goals have been attained, pursuant to Section 10.5(a) of the LTIP.  PG&E Corporation will issue shares as soon as practicable after such determination, but no earlier than the Vesting Date, and not later than March 15 of the calendar year following completion of the Performance Period.
Dividends	Each time that PG&E Corporation declares a dividend on its shares of common stock, an amount equal to the dividend multiplied by the number of Performance Shares granted to you by this Agreement will be accrued on your behalf.  If you receive a Performance Share settlement in accordance with the preceding paragraph, at that same time you also will receive a cash payment equal to the amount of any dividends accrued with respect to your Performance Shares over the Performance Period multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Voluntary Termination	If you terminate your employment with PG&E Corporation voluntarily before the Vesting Date (other than for Retirement), all of the Performance Shares will be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares will be forfeited.
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause before the Vesting Date, all of the Performance Shares will be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares will be forfeited. For these purposes, "cause" means when PG&E Corporation, acting in good faith based upon information then known to it, determines that you have engaged in, committed, or are responsible for, (1) serious misconduct, gross negligence, theft, or fraud against PG&E Corporation and/or its affiliates, (2) refusal or unwillingness to perform your duties; (3) inappropriate conduct in violation of PG&E Corporation's equal employment opportunity policy; (4) conduct which reflects adversely upon, or making any remarks disparaging of, PG&E Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries; (5) insubordination; (6) any willful act that is likely to have the effect of injuring the reputation, business, or business relationships of PG&E Corporation or its subsidiaries or affiliates; (7) violation of any fiduciary duty; or (8) breach of any duty of loyalty.

Termination other than for Cause	Upon your termination (other than termination for cause, voluntary termination, Retirement, termination due to death or Disability, or termination in connection with a Change in Control) the number of vested Performance Shares will equal the number of Performance Shares subject to this Agreement, multiplied by the number of your days of service with PG&E Corporation in the vesting period (through the date of termination), divided by the potential number of days of service in the vesting period.  All other outstanding Performance Shares  will be cancelled, and associated accrued dividends will be forfeited, upon such termination. Your vested Performance Shares will be settled, if at all, as soon as practicable after the Vesting Date and no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applied to active employees. At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Retirement	If you retire before the Vesting Date, your outstanding Performance Shares will continue to vest as though your employment had continued and will be settled, if at all, as soon as practicable following the Vesting Date and no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applicable to active employees.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.   Your termination of employment will be considered a Retirement if you are age 55 or older on the date of termination (other than termination for cause) and if you were employed by PG&E Corporation for at least five consecutive years ending on the date of termination of your employment.
Death/Disability	If your employment terminates due to your death or disability before the Vesting Date, all of your Performance Shares will immediately vest and will be settled, if at all, as soon as practicable after the Vesting Date and no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applied to active employees.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Termination Due to Disposition of Subsidiary	If your employment is terminated (other than for cause, your voluntary termination, or Retirement) (1) 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, or (2) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, then your outstanding Performance Shares will 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 Performance Shares subject to this Agreement. If the Acquiror assumes or continues PG&E Corporation's rights and obligations under this Agreement or substitutes a substantially equivalent award, Performance Shares will vest on the Vesting Date and performance will be deemed to have been achieved at target, resulting in a payout percentage of 100%.  Settlement will occur as soon as practicable after the Vesting Date and no later than March 15 of the year following completion of the Performance Period.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares over the Performance Period multiplied by a payout percentage of 100%. If the Change in Control of PG&E Corporation occurs before the Vesting Date, and if this award is neither assumed nor continued by the Acquiror or if the Acquiror does not provide a substantially equivalent award in substitution for the Performance Shares subject to this Agreement, all of your outstanding Performance Shares will vest and become nonforfeitable on the date of the Change in Control.  Such vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date and no later than March 15 of the year following completion of the Performance Period.  Performance will be deemed to have been achieved at target and the payout percentage will be 100%. At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares to the date of the Change in Control multiplied by a payout percentage of 100%.
Termination In Connection with a Change in Control	If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within two years following the Change in Control, all of your outstanding Performance Shares (to the extent they did not previously vest upon failure of the Acquiror to assume or continue this award) will vest and become nonforfeitable on the date of termination of your employment. If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Performance Shares will vest in full and become nonforfeitable (including the portion that you would have otherwise forfeited based on the proration of vested Performance Shares through the date of termination of your employment) as of the date of the Change in Control. Your vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date but no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applied to active employees (which in this case will be deemed to be at target, consistent with the "Change in Control" section, above).  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any. PG&E Corporation has the sole discretion to determine whether termination of your employment was made in connection with a Change in Control.
Withholding Taxes	The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of your Performance Shares 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 Performance Shares 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." 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.

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.
Recoupment of Awards	Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

EX-10.32

EXHIBIT 10.32

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

NON-ANNUAL RESTRICTED STOCK UNIT AWARD

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:November 28, 2016

Name of Recipient:Ed Halpin

Recipient's Participant ID:XXXXXXXX

Number of Restricted Stock Units:16,464

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 award, the attached Agreement, and a copy of the prospectus describing the LTIP and the Restricted Stock Units dated March 1, 2016.

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 will 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 2012 Officer Severance Policy, this Agreement will govern. For purposes of this Agreement, employment with PG&E Corporation means 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 (the "Normal Vesting Schedule") <vesting_schedule> 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 will then be 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 will 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 will, 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, 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 will 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 will 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	(If your employment is terminated (other than termination for cause, your voluntary termination) (1) 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) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, then your Restricted Stock Units will 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 will 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) will 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) will 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 has the sole discretion to determine whether termination of your employment was made in connection with a Change in Control
Delay	PG&E Corporation will 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 will 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 will 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 will 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.
Recoupment of Awards	Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

EX-10.55

EXHIBIT 10.55

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT AWARD

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:March 1, 2016

Name of Recipient:<First_Name> <Last_Name>

Recipient's Participant ID:<Emp_Id>

Number of Restricted Stock Units:<shares_awarded>

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 award, the attached Agreement, and a copy of the prospectus describing the LTIP and the Restricted Stock Units dated March 1, 2016.

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, 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 will 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 2012 Officer Severance Policy, this Agreement will govern. For purposes of this Agreement, employment with PG&E Corporation means 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 on the cover sheet, will vest in accordance with the below vesting schedule (the "Normal Vesting Schedule").           March 1, 2017 – one-third of the Restricted Stock Units           March 1, 2018 – one-third of the Restricted Stock Units           March 1, 2019 – one-third of the Restricted Stock Units 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 will then be 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 will 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 will, 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 will vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such Retirement.  Your termination of employment will be considered Retirement if you are both age 55 or older on the date of termination (other than termination for cause) 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 or Retirement, 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 will 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 will 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	If your employment is terminated (other than for cause, your voluntary termination, or your Retirement) (1) 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) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, then your Restricted Stock Units will 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 will 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, 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) will 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) will 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 has the sole discretion to determine whether termination of your employment was made in connection with a Change in Control.
Delay	PG&E Corporation will 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 will 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 will 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 will 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.
Recoupment of Awards	Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

EX-10.61

EXHIBIT 10.61

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

PERFORMANCE SHARE AWARD – FINANCIAL

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

Date of Grant:March 1, 2016

Name of Recipient:<First_Name> <Last_Name>

Recipient's Participant ID:<Emp_Id>

Number of Performance Shares:<shares_awarded>

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 award, the attached Agreement, and a copy of the prospectus describing the LTIP and the Performance Shares dated March 1, 2016.

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, Pacific Gas and Electric Company, 245 Market Street, N2T, San Francisco, 94105.

Attachment

PG&E CORPORATION

2014 LONG-TERM INCENTIVE PLAN

PERFORMANCE SHARE AGREEMENT- FINANCIAL

The LTIP and Other Agreements	This Agreement constitutes the entire understanding between you and PG&E Corporation regarding the Performance Shares, 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 will 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 2012 Officer Severance Policy, this Agreement will govern.  The LTIP provides the Committee with discretion to adjust the performance award formula. For purposes of this Agreement, employment with PG&E Corporation means employment with any member of the Participating Company Group.
Grant of Performance Shares	PG&E Corporation grants you the number of Performance Shares shown on the cover sheet of this Agreement (the "Performance Shares").  The Performance Shares are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Performance Shares Settlement in Shares/ Performance Goals	As long as you remain employed with PG&E Corporation, the Performance Shares will vest upon, and to the extent of, the Committee's certification of the extent to which performance goals have been attained for this award, which certification will occur on or after January 1 but before March 15 of the third year following the calendar year of grant specified in the cover sheet (the "Vesting Date").  Except as described below, all Performance Shares that have not vested will be cancelled upon termination of your employment. Vested Performance Shares will be settled in shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. The number of shares you are entitled to receive will be calculated by multiplying the number of vested Performance Shares by the "rounded payout percentage" determined as follows (except as set forth elsewhere in this Agreement), rounded to the nearest whole number:
	Upon the Vesting Date, PG&E Corporation's total shareholder return ("TSR") will be compared to the TSR of the fourteen other companies in PG&E Corporation's comparator group1 for the prior three calendar years, consisting of 2016, 2017, and 2018 (the "Performance Period").2  Subject to rounding considerations, if PG&E Corporation's TSR falls below the 25th percentile of the comparator group the payout percentage will be 0%; if PG&E Corporation's TSR is at the 25th percentile, the payout percentage will be 25%; if PG&E Corporation's TSR is at the 60th percentile, the payout percentage will be 100%; and if PG&E Corporation's TSR is in the 90th percentile or higher, the payout percentage will be 200%.  If PG&E Corporation's TSR performance is between the 25th percentile and the target, or between the target and the 90th percentile, the rounded payout percentage is determined by straight-line interpolation between the performance percentile associated with each comparator rank and between the rounded payouts associated with each performance percentile (including the 25th, 60th, and 90th percentiles) as shown in above table, rounded down to the nearest whole number.  The following table sets forth the rounded payout percentages for the TSR rankings that could be achieved by companies within the comparator group: Number of Companies inTotal (excluding PG&E Corporation)   - 14                                                        Performance                  Rounded                                Rank                Percentile                        Payout                                  1                        100%                             200%                                   2                          93%                             200%                                                               90%                             200%                                  3                          86%                             186%                                  4                          79%                             162%                                  5                          71%                             138%                                   6                          64%                             114%                                                               60%                             100%                                  7                          57%                              94%                                  8                          50%                              79%                                  9                          43%                              63%                                10                          36%                              48%                                11                          29%                              33%                                                               25%                              25%                                 12                          21%                                0%                                 13                          14%                                0%                                 14                            7%                                0% The payout percentage, if any, will be determined as soon as practicable following the date that the Committee (or a subcommittee of that Committee) or an equivalent body certifies the extent to which performance goals have been attained, pursuant to Section 10.5(a) of the LTIP.  PG&E Corporation will issue shares as soon as practicable after such determination, but no earlier than the Vesting Date, and not later than March 15 of the calendar year following completion of the Performance Period.
	(1) The current Performance Comparator Group consists of the following companies:  Ameren Corporation, American Electric Power, CMS Energy, Consolidated Edison, Inc., DTE Energy, Duke Energy, Edison International, Eversource Energy, NiSource, Inc., Pinnacle West Capital, SCANA Corp., Southern Company, Wisconsin Energy Corporation, and Xcel Energy, Inc.  PG&E Corporation reserves the right to change the companies comprising the comparator group and the resulting payout percentage table in accordance with the rules established by PG&E Corporation in connection with this award. (2) PG&E Corporation's TSR performance is measured by the value of stock price appreciation and dividends paid and reinvested, relative to companies in the Performance Comparator Group.  For these purposes, average share price will be measured by comparing the average per share closing price of PG&E Corporation common stock during the 20 trading days before the beginning and the end of the Performance Period.
Dividends	Each time that PG&E Corporation declares a dividend on its shares of common stock, an amount equal to the dividend multiplied by the number of Performance Shares granted to you by this Agreement will be accrued on your behalf.  If you receive a Performance Share settlement in accordance with the preceding paragraph, at that same time you also will receive a cash payment equal to the amount of any dividends accrued with respect to your Performance Shares over the Performance Period multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Voluntary Termination	If you terminate your employment with PG&E Corporation voluntarily before the Vesting Date (other than for Retirement), all of the Performance Shares will be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares will be forfeited.
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause before the Vesting Date, all of the Performance Shares will be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares will be forfeited.  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 or Retirement before the Vesting Date, a portion of your outstanding Performance Shares will vest proportionally based on the number of months during the Performance Period that you were employed (rounded down) divided by the number of months in the Performance Period (36 months).  All other outstanding Performance Shares will be cancelled, and any associated accrued dividends will be forfeited, unless your termination of employment was in connection with a Change in Control as provided below. Your vested Performance Shares will be settled, if at all, as soon as practicable after the Vesting Date and no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applied to active employees.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Retirement	If you retire before the Vesting Date, your outstanding Performance Shares will continue to vest as though your employment had continued and will be settled, if at all, as soon as practicable following the Vesting Date and no later than March 15 of the year following completion of the Performance Period based on the same payout percentage applicable to active employees.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.  Your termination of employment will be considered a Retirement if you are age 55 or older on the date of termination (other than termination for cause) and if you were employed by PG&E Corporation for at least five consecutive years ending on the date of termination of your employment.
Death/Disability	If your employment terminates due to your death or disability before the Vesting Date, all of your Performance Shares will vest immediately and will be settled, if at all, as soon as practicable after the Vesting Date and no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applied to active employees.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Termination Due to Disposition of Subsidiary	If your employment is terminated (other than for cause, your voluntary termination, or Retirement) (1) 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, or (2) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, then your outstanding Performance Shares will 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 Performance Shares subject to this Agreement. If the Acquiror assumes or continues PG&E Corporation's rights and obligations under this Agreement or substitutes a substantially equivalent award, TSR will be calculated by combining (a) the TSR of PG&E Corporation for the period from January 1 of the year of grant to the date of the Change in Control, and (b) the TSR of the Acquiror from the date of the Change in Control to the last day of the Performance Period. The number of shares, if any, you are entitled to receive upon settlement of the assumed, continued or substituted Performance Share award will be  determined based on the rounded payout percentage reflected in the table set forth above for the highest percentile TSR performance met or exceeded when calculated on that basis, and considering any adjustments to the comparator group.  Settlement will occur as soon as practicable after the Vesting Date and no later than March 15 of the year following completion of the Performance Period.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares over the Performance Period multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any. If the Change in Control of PG&E Corporation occurs before the Vesting Date, and if this award is neither assumed nor continued by the Acquiror or if the Acquiror does not provide a substantially equivalent award in substitution for the Performance Shares subject to this Agreement, all of your outstanding Performance Shares will vest and become nonforfeitable on the date of the Change in Control.  Such vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date and no later than March 15 of the year following completion of the Performance Period.  The payout percentage, if any, will be based on TSR for the period from January 1 of the year of grant to the date of the Change in Control compared to the TSR of the other companies in PG&E Corporation's comparator group for the same period. At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares to the date of the Change in Control multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Termination In Connection with a Change in Control	If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within two years following the Change in Control, all of your outstanding Performance Shares (to the extent they did not previously vest upon failure of the Acquiror to assume or continue this award) will vest and become nonforfeitable on the date of termination of your employment. If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Performance Shares will vest in full and become nonforfeitable (including the portion that you would have otherwise forfeited based on the proration of vested Performance Shares through the date of termination of your employment) as of the date of the Change in Control. Your vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date and no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applied to active employees (determined consistent with the method described above under "Change in Control"). At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any. PG&E Corporation has the sole discretion to determine whether termination of your employment was made in connection with a Change in Control.
Withholding Taxes	The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of your Performance Shares 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 Performance Shares 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." 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.

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.
Recoupment of Awards	Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

EX-10.63

EXHIBIT 10.63

PG&E CORPORATION 2014 LONG-TERM INCENTIVE PLAN

PERFORMANCE SHARE AWARD – SAFETY AND AFFORDABILITY

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

Date of Grant:March 1, 2016

Name of Recipient:<First_Name> <Last_Name>

Recipient's Participant ID:<Emp_Id>

Number of Performance Shares:<shares_awarded>

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 award, the attached Agreement, and a copy of the prospectus describing the LTIP and the Performance Shares dated March 1, 2016.

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, Pacific Gas and Electric Company, 245 Market Street, N2T, San Francisco, 94105.

Attachment

PG&E CORPORATION

2014 LONG-TERM INCENTIVE PLAN

PERFORMANCE SHARE AGREEMENT

SAFETY AND AFFORDABILITY

The LTIP and Other Agreements	This Agreement constitutes the entire understanding between you and PG&E Corporation regarding the Performance Shares, 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 will 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 2012 Officer Severance Policy, this Agreement will govern.  The LTIP provides the Committee with discretion to adjust the performance award formula. For purposes of this Agreement, employment with PG&E Corporation means employment with any member of the Participating Company Group.
Grant of Performance Shares	PG&E Corporation grants you the number of Performance Shares shown on the cover sheet of this Agreement (the "Performance Shares").  The Performance Shares are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Performance Shares Settlement in Shares/ Performance Goals	As long as you remain employed with PG&E Corporation, the Performance Shares will vest upon, and to the extent of, the Committee's certification of the extent to which performance goals have been attained for this award, which certification will occur on or after January 1 but before March 15 of the third year following the calendar year of grant specified in the cover sheet (the "Vesting Date").  Except as described below, all Performance Shares that have not vested will be cancelled upon termination of your employment. Vested Performance Shares will be settled in shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. The number of shares you are entitled to receive will be calculated by multiplying the number of vested Performance Shares by the "payout percentage" determined as follows (except as set forth elsewhere in this Agreement), rounded to the nearest whole number:
	Fifty percent of the Performance Shares have a safety performance goal and resulting safety payout percentage, and the other fifty percent of the Performance Shares have an affordability performance goal and resulting affordability payout percentage.  Subject to rounding considerations, in each case, if performance is below threshold, the payout percentage will be 0%; if performance is at threshold, the payout percentage will be 25%; if performance is at target, the payout percentage will be 100%; and if performance is at or better than maximum, the payout percentage will be 200%.  The actual payout percentage for performance between threshold and maximum will be determined based on linear interpolation between the payout percentages for threshold and target, or target and maximum, as appropriate. The measures and goals are discussed in more detail below: Safety - At the end of 2018, PG&E Corporation's lost workday ("LWD") case rate ("LWD Rate") for that year will be measured as the number of LWD cases incurred per 200,000 hours worked during 2018. LWD cases will be measured in the same manner as for the 2016 Short-Term Incentive Plan, will include OSHA recordable incidents that result in loss of at least one workday, and will exclude fatalities.  Threshold performance is 0.247, target performance is 0.215, and maximum performance is 0.201. Affordability - PG&E Corporation's affordability performance will be measured as the reduction in standard rate case expense for unitized work and support operations and maintenance costs over the three calendar years prior to the normal Vesting Date (the "Performance Period"), as compared to escalated actual costs in these areas for 2014, escalated by two years (at 2.75 perent per year) , as determined in the sole discretion of the Committee in accordance with the terms adopted by the Committee at its February 16, 2016 meeting.  Threshold performance is $75 million, target performance is $100 million, and maximum performance is $200 million. The final payout percentages, if any, will be determined as soon as practicable following the date that the Committee (or a subcommittee of that Committee) or an equivalent body certifies the extent to which the performance goals have been attained, pursuant to Section 10.5(a) of the LTIP.  PG&E Corporation will issue shares as soon as practicable after such determination, but no earlier than the Vesting Date, and not later than March 15 of the calendar year following completion of the Performance Period.
Dividends	Each time that PG&E Corporation declares a dividend on its shares of common stock, an amount equal to the dividend multiplied by the number of Performance Shares granted to you by this Agreement will be accrued on your behalf.  If you receive a Performance Share settlement in accordance with the preceding paragraph, at that same time you also will receive a cash payment equal to the amount of any dividends accrued with respect to your Performance Shares over the Performance Period multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Voluntary Termination	If you terminate your employment with PG&E Corporation voluntarily before the Vesting Date (other than for Retirement), all of the Performance Shares will be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares will be forfeited.
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause before the Vesting Date, all of the Performance Shares will be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares will be forfeited.  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 or Retirement before the Vesting Date, a portion of your outstanding Performance Shares will vest proportionally based on the number of months during the Performance Period that you were employed (rounded down) divided by the number of months in the Performance Period (36 months).  All other outstanding Performance Shares will be cancelled, and any associated accrued dividends will be forfeited, unless your termination of employment was in connection with a Change in Control as provided below. Your vested Performance Shares will be settled, if at all, as soon as practicable after the Vesting Date and no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applied to active employees.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Retirement	If you retire before the Vesting Date, your outstanding Performance Shares will continue to vest as though your employment had continued and will be settled, if at all, as soon as practicable following the Vesting Date and no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applicable to active employees.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.   Your termination of employment will be considered a Retirement if you are age 55 or older on the date of termination (other than termination for cause) and if you were employed by PG&E Corporation for at least five consecutive years ending on the date of termination of your employment.
Death/Disability	If your employment terminates due to your death or disability before the Vesting Date, all of your Performance Shares will immediately vest and will be settled, if at all, as soon as practicable after the Vesting Date and no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applied to active employees.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any.
Termination Due to Disposition of Subsidiary	If your employment is terminated (other than for cause, your voluntary termination, or Retirement) (1) 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, or (2) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, then your outstanding Performance Shares will 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 Performance Shares subject to this Agreement. If the Acquiror assumes or continues PG&E Corporation's rights and obligations under this Agreement or substitutes a substantially equivalent award, Performance Shares will vest on the Vesting Date, and performance will be deemed to have been achieved at target, resulting in a payout percentage of 100%. Settlement will occur as soon as practicable after the Vesting Date and no later than March 15 of the year following completion of the Performance Period.  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares over the Performance Period multiplied by a payout percentage of 100%. If the Change in Control of PG&E Corporation occurs before the Vesting Date, and if this award is neither assumed nor continued by the Acquiror or if the Acquiror does not provide a substantially equivalent award in substitution for the Performance Shares subject to this Agreement, all of your outstanding Performance Shares will vest and become nonforfeitable on the date of the Change in Control.  Such vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date and no later than March 15 of the year following completion of the Performance Period.  Performance will be deemed to have been achieved at target and the payout percentage will be 100%. At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares to the date of the Change in Control multiplied by a payout percentage of 100%.
Termination In Connection with a Change in Control	If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within two years following the Change in Control, all of your outstanding Performance Shares (to the extent they did not previously vest upon failure of the Acquiror to assume or continue this award) will vest and become nonforfeitable on the date of termination of your employment. If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Performance Shares will vest in full and become nonforfeitable (including the portion that you would have otherwise forfeited based on the proration of vested Performance Shares through the date of termination of your employment) as of the date of the Change in Control. Your vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date but no later than March 15 of the year following completion of the Performance Period, based on the same payout percentage applied to active employees (which in this case will be deemed to be at target, consistent with the "Change in Control" section, above).  At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any. PG&E Corporation has the sole discretion to determine whether termination of your employment was made in connection with a Change in Control.
Withholding Taxes	The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of your Performance Shares 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 Performance Shares 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." 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.

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.
Recoupment of Awards	Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

EX-12.01

EXHIBIT 12.1

EXHIBIT 12.1PACIFIC GAS AND ELECTRIC COMPANYCOMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Year Ended December 31,
(in millions)	2016		2015			2014		2013		2012
Earnings:
Net income	$	1,402	$	862		$	1,433	$	866	$	811
Income tax provision (benefit)		70		(19	)		384		326		298
Fixed charges		1,417		1,260			1,176		971		891
Total earnings	$	2,889	$	2,103		$	2,993	$	2,163	$	2,000
Fixed charges:
Interest on short-term borrowings
and long-term debt, net	$	1,363	$	1,208		$	1,125	$	917	$	834
Interest on capital leases		3		4			6		7		9
AFUDC debt		51		48			45		47		48
Total fixed charges	$	1,417	$	1,260		$	1,176	$	971	$	891
Ratios of earnings to fixed charges		2.04		1.67			2.55		2.23		2.24

Note:

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

EX-12.02

EXHIBIT 12.2

EXHIBIT 12.2PACIFIC GAS AND ELECTRIC COMPANYCOMPUTATION OF RATIOS OF EARNINGS TO COMBINEDFIXED CHARGES AND PREFERRED STOCK DIVIDENDS

	Year Ended December 31,
(in millions)	2016		2015			2014		2013		2012
Earnings:
Net income	$	1,402	$	862		$	1,433	$	866	$	811
Income tax provision (benefit)		70		(19	)		384		326		298
Fixed charges		1,417		1,260			1,176		971		891
Total earnings	$	2,889	$	2,103		$	2,993	$	2,163	$	2,000
Fixed charges:
Interest on short-term borrowings
and long-term debt, net	$	1,363	$	1,208		$	1,125	$	917	$	834
Interest on capital leases		3		4			6		7		9
AFUDC debt		51		48			45		47		48
Total fixed charges	$	1,417	$	1,260		$	1,176	$	971	$	891
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		5			6		7		7
Total preferred stock dividends		14		14			15		16		16
Total combined fixed charges
and preferred stock
dividends	$	1,431	$	1,274		$	1,191	$	987	$	907
Ratios of earnings to combined
fixed charges and preferred
stock dividends		2.02		1.65			2.51		2.19		2.21

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

EXHIBIT 12.3

PG&E CORPORATION

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Year Ended December 31,
(in millions)	2016			2015			2014			2013			2012
Earnings:
Net income	$	1,407		$	888		$	1,450		$	828		$	830
Income tax provision (benefit)		55			(27	)		345			268			237
Fixed charges		1,440			1,284			1,206			1,012			931
Pre-tax earnings required to cover
the preferred stock dividend of
consolidated subsidiaries		(14	)		(14	)		(15	)		(16	)		(15	)
Total earnings	$	2,888		$	2,131		$	2,986		$	2,092		$	1,983
Fixed charges:
Interest on short-term
borrowings and long-term
debt, net	$	1,372		$	1,218		$	1,140		$	942		$	859
Interest on capital leases		3			4			6			7			9
AFUDC debt		51			48			45			47			48
Pre-tax earnings required to cover
the preferred stock dividend of
consolidated subsidiaries		14			14			15			16			15
Total fixed charges	$	1,440		$	1,284		$	1,206		$	1,012		$	931
Ratios of earnings to fixed charges		2.01			1.66			2.48			2.07			2.13

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 Statement No. 333-215425 on Form S-3, 333-209586 on Form S-3ASR, and 333-129422, 333-176090, 333-195902 and 333-206457 on Form S-8 of PG&E Corporation and Registration Statement No. 333-215427 on Form S-3 of Pacific Gas and Electric Company of our reports dated February 16, 2017, 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, 2016.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 16, 2017

EX-24

EXHIBIT 24

POWER OF ATTORNEY

Each of the undersigned Directors of PG&E Corporation hereby constitutes and appoints JOHN R. SIMON, 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, 2016 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 15th day of February, 2017.

/s/ Lewis Chew	/s/ Forrest E. Miller
Lewis Chew /s/ Anthony F. Earley, Jr.	Forrest E. Miller /s/ Eric D. Mullins
Anthony F. Earley, Jr. /s/ Fred J. Fowler	Eric D. Mullins /s/ Rosendo G. Parra
Fred J. Fowler /s/ Maryellen C. Herringer	Rosendo G. Parra /s/ Barbara L. Rambo
Maryellen C. Herringer /s/ Richard C. Kelly	Barbara L. Rambo /s/ Anne Shen Smith
Richard C. Kelly /s/ Roger H. Kimmel	Anne Shen Smith /s/ Barry Lawson Williams
Roger H. Kimmel /s/ Richard A. Meserve	Barry Lawson Williams
Richard A. Meserve

POWER OF ATTORNEY

Each of the undersigned Directors of Pacific Gas and Electric Company hereby constitutes and appoints JOHN R. SIMON, 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, 2016 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 15th day of February, 2017.

/s/ Lewis Chew	/s/ Eric D. Mullins
Lewis Chew /s/ Anthony F. Earley, Jr.	Eric D. Mullins /s/ Rosendo G. Parra
Anthony F. Earley, Jr. /s/ Fred J. Fowler	Rosendo G. Parra /s/ Barbara L. Rambo
Fred J. Fowler /s/ Maryellen C. Herringer	Barbara L. Rambo /s/ Anne Shen Smith
Maryellen C. Herringer /s/ Richard C. Kelly	Anne Shen Smith /s/ Nickolas Stavropoulos
Richard C. Kelly /s/ Roger H. Kimmel	Nickolas Stavropoulos /s/ Barry Lawson Williams
Roger H. Kimmel /s/ Richard A. Meserve	Barry Lawson Williams /s/ Geisha J. Williams
Richard A. Meserve /s/ Forrest E. Miller	Geisha J. Williams
Forrest E. Miller

EX-31.01

EXHIBIT 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Anthony F. Earley, Jr., certify that:

1. I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2016 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 16, 2017	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, 2016 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 16, 2017	JASON P. WELLS
	Jason P. Wells
	Senior Vice President and Chief Financial Officer

EX-31.02

EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Nickolas Stavropoulos, certify that:

1. I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2016 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 16, 2017	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, 2016 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 16, 2017	GEISHA J. WILLIAMS
	Geisha J. Williams
	President, Electric

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, David S. Thomason, certify that:

1. I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2016 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 16, 2017	DAVID S. THOMASON
	David S. Thomason
	Vice President, Chief Financial Officer and Controller

EX-32.01

EXHIBIT 32.1

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, 2016 ("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 16, 2017

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, 2016 ("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 16, 2017

EX-32.02

EXHIBIT 32.2

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, 2016 ("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 16, 2017

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, 2016 ("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 16, 2017

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, 2016 ("Form 10-K"), I, David S. Thomason, 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.

DAVID S. THOMASON

DAVID S. THOMASON

Vice President, Chief Financial Officer and Controller

February 16, 2017

XML

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Feb. 07, 2017	Jun. 30, 2016
Document Type	10-K
Document Period End Date	Dec. 31, 2016
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	2016
Entity Current Reporting Status	Yes
Trading Symbol	PCG
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Public Float			$ 31,807
Entity Common Stock, Shares Outstanding		507,782,249
Pacific Gas And Electric Company [Member]
Document Type	10-K
Document Period End Date	Dec. 31, 2016
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	2016
Entity Current Reporting Status	Yes
Trading Symbol	PCG
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	No
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Revenues
Electric	$ 13,864	$ 13,657	$ 13,658
Natural gas	3,802	3,176	3,432
Total operating revenues	17,666	16,833	17,090
Operating Expenses
Cost of electricity	4,765	5,099	5,615
Cost of natural gas	615	663	954
Operating and maintenance	7,354	6,951	5,638
Depreciation, amortization, and decommissioning	2,755	2,612	2,433
Total operating expenses	15,489	15,325	14,640
Operating Income	2,177	1,508	2,450
Interest income	23	9	9
Interest expense	(829)	(773)	(734)
Other income (expense)	91	117	70
Income Before Income Taxes	1,462	861	1,795
Income tax provision (benefit)	55	(27)	345
Net Income	1,407	888	1,450
Preferred stock dividend requirement of subsidiary	14	14	14
Income Available for Common Shareholders	$ 1,393	$ 874	$ 1,436
Weighted Average Common Shares Outstanding, Basic	499	484	468
Weighted Average Common Shares Outstanding, Diluted	501	487	470
Net earnings per common share, basic	$ 2.79	$ 1.81	$ 3.07
Net Earnings Per Common Share, Diluted	$ 2.78	$ 1.79	$ 3.06
Pacific Gas And Electric Company [Member]
Operating Revenues
Electric	$ 13,865	$ 13,657	$ 13,656
Natural gas	3,802	3,176	3,432
Total operating revenues	17,667	16,833	17,088
Operating Expenses
Cost of electricity	4,765	5,099	5,615
Cost of natural gas	615	663	954
Operating and maintenance	7,352	6,949	5,635
Depreciation, amortization, and decommissioning	2,754	2,611	2,432
Total operating expenses	15,486	15,322	14,636
Operating Income	2,181	1,511	2,452
Interest income	22	8	8
Interest expense	(819)	(763)	(720)
Other income (expense)	88	87	77
Income Before Income Taxes	1,472	843	1,817
Income tax provision (benefit)	70	(19)	384
Net Income	1,402	862	1,433
Preferred stock dividend requirement	14	14	14
Income Available for Common Shareholders	$ 1,388	$ 848	$ 1,419

XML

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net income	$ 1,407	$ 888	$ 1,450
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (related to PG&E Corporation net of income tax of $1, $0 and $10 and related to the Utility of $1, $1, and $6, at respective dates)	(2)	(1)	(14)
Net change in investments (net of taxes $0, $12, and $17, at respective dates)	0	(17)	(25)
Total other comprehensive income (loss)	(2)	(18)	(39)
Comprehensive Income	1,405	870	1,411
Preferred stock dividend requirement of subsidiary	14	14	14
Comprehensive Income Attributable to Common Shareholders	1,391	856	1,397
Pacific Gas And Electric Company [Member]
Net income	1,402	862	1,433
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (related to PG&E Corporation net of income tax of $1, $0 and $10 and related to the Utility of $1, $1, and $6, at respective dates)	(1)	(2)	(8)
Total other comprehensive income (loss)	(1)	(2)	(8)
Comprehensive Income	$ 1,401	$ 860	$ 1,425

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Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension and other postretirement benefit plans obligations tax	$ 1	$ 0	$ 10
Change in investments tax	0	12	17
Pacific Gas And Electric Company [Member]
Pension and other postretirement benefit plans obligations tax	$ 1	$ 1	$ 6

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 177	$ 123
Restricted cash	7	234
Accounts receivable
Customers (net of allowance for doubtful accounts of $58 and $54 at respective dates)	1,252	1,106
Accrued unbilled revenue	1,098	855
Regulatory balancing accounts	1,500	1,760
Other	801	286
Regulatory assets	423	517
Inventories
Gas stored underground and fuel oil	117	126
Materials and supplies	346	313
Income taxes receivable	160	155
Other	283	338
Total current assets	6,164	5,813
Property, Plant, and Equipment
Electric	52,556	48,532
Gas	17,853	16,749
Construction work in progress	2,184	2,059
Other	2	2
Total property, plant, and equipment	72,595	67,342
Accumulated depreciation	(22,014)	(20,619)
Net property, plant, and equipment	50,581	46,723
Other Noncurrent Assets
Regulatory assets	7,951	7,029
Nuclear decommissioning trusts	2,606	2,470
Income taxes receivable	70	135
Other	1,226	1,064
Total other noncurrent assets	11,853	10,698
TOTAL ASSETS	68,598	63,234
Current Liabilities
Short-term borrowings	1,516	1,019
Long-term debt, classified as current	700	160
Accounts payable
Trade creditors	1,495	1,414
Regulatory balancing accounts	645	715
Other	433	398
Disputed claims and customer refunds	236	454
Interest payable	216	206
Other	2,323	1,997
Total current liabilities	7,564	6,363
Noncurrent Liabilities
Long-term debt	16,220	15,925
Regulatory liabilities	6,805	6,321
Pension and other postretirement benefits	2,641	2,622
Asset retirement obligations	4,684	3,643
Deferred income taxes	10,213	9,206
Other	2,279	2,326
Total noncurrent liabilities	42,842	40,043
Commitments and Contingencies (Note 13)
Shareholders' Equity
Common stock	12,198	11,282
Reinvested earnings	5,751	5,301
Accumulated other comprehensive(loss)income	(9)	(7)
Total shareholders' equity	17,940	16,576
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	18,192	16,828
TOTAL LIABILITIES AND EQUITY	68,598	63,234
Pacific Gas And Electric Company [Member]
Current Assets
Cash and cash equivalents	71	59
Restricted cash	7	234
Accounts receivable
Customers (net of allowance for doubtful accounts of $58 and $54 at respective dates)	1,252	1,106
Accrued unbilled revenue	1,098	855
Regulatory balancing accounts	1,500	1,760
Other	801	284
Regulatory assets	423	517
Inventories
Gas stored underground and fuel oil	117	126
Materials and supplies	346	313
Income taxes receivable	159	130
Other	282	338
Total current assets	6,056	5,722
Property, Plant, and Equipment
Electric	52,556	48,532
Gas	17,853	16,749
Construction work in progress	2,184	2,059
Total property, plant, and equipment	72,593	67,340
Accumulated depreciation	(22,012)	(20,617)
Net property, plant, and equipment	50,581	46,723
Other Noncurrent Assets
Regulatory assets	7,951	7,029
Nuclear decommissioning trusts	2,606	2,470
Income taxes receivable	70	135
Other	1,110	958
Total other noncurrent assets	11,737	10,592
TOTAL ASSETS	68,374	63,037
Current Liabilities
Short-term borrowings	1,516	1,019
Long-term debt, classified as current	700	160
Accounts payable
Trade creditors	1,494	1,414
Regulatory balancing accounts	645	715
Other	453	418
Disputed claims and customer refunds	236	454
Interest payable	214	203
Other	2,072	1,750
Total current liabilities	7,330	6,133
Noncurrent Liabilities
Long-term debt	15,872	15,577
Regulatory liabilities	6,805	6,321
Pension and other postretirement benefits	2,548	2,534
Asset retirement obligations	4,684	3,643
Deferred income taxes	10,510	9,487
Other	2,230	2,282
Total noncurrent liabilities	42,649	39,844
Commitments and Contingencies (Note 13)
Shareholders' Equity
Preferred stock	258	258
Common stock	1,322	1,322
Additional paid-in capital	8,050	7,215
Reinvested earnings	8,763	8,262
Accumulated other comprehensive(loss)income	2	3
Total shareholders' equity	18,395	17,060
TOTAL LIABILITIES AND EQUITY	$ 68,374	$ 63,037

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Allowance for doubtful accounts	$ 58	$ 54
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	800,000,000	800,000,000
Common stock, shares outstanding	506,891,874	492,025,443
Pacific Gas And Electric Company [Member]
Allowance for doubtful accounts	$ 58	$ 54
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

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Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flows from Operating Activities
Net income	$ 1,407	$ 888	$ 1,450
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,755	2,612	2,433
Allowance for equity funds used during construction	(112)	(107)	(100)
Deferred income taxes and tax credits, net	1,030	693	690
Charge for disallowed capital	507	407	116
Other	379	326	286
Butte-related third-party claims	690	0	0
Butte-related insurance receivable	575	0	0
Effect of changes in operating assets and liabilities:
Accounts receivable	(473)	(177)	13
Inventories	(24)	37	(22)
Accounts payable	180	(55)	(61)
Income taxes receivable/payable	(5)	43	376
Other current assets and liabilities	83	(288)	218
Regulatory assets, liabilities, and balancing accounts, net	(1,214)	(244)	(1,642)
Other noncurrent assets and liabilities	(219)	(355)	(67)
Net cash provided by operating activities	4,409	3,780	3,690
Cash Flows from Investing Activities
Capital expenditures	(5,709)	(5,173)	(4,833)
Decrease in restricted cash	227	64	3
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,295	1,268	1,336
Purchases of nuclear decommissioning trust investments	(1,352)	(1,392)	(1,334)
Other	13	22	114
Net cash used in investing activities	(5,526)	(5,211)	(4,714)
Cash Flows from Financing Activities
Borrowings (repayments) under revolving credit facilities	0	0	(260)
Net issuances (repayments) of commercial paper, net of discount of $6, $3, and $2 at respective dates	(9)	683	(583)
Short-term debt financing	500	0	300
Short-term debt matured	0	(300)	0
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of (for PG&E Corporaiton $17, $27, and $17 and for the Utility $17, $27, and $17, at respective dates)	983	1,123	2,308
Repayments of long-term debt	(160)	0	(889)
Common stock issued	822	780	802
Common stock dividends paid	(921)	(856)	(828)
Other	(44)	(27)	29
Net cash provided by (used in) financing activities	1,171	1,403	879
Net change in cash and cash equivalents	54	(28)	(145)
Cash and cash equivalents at January 1	123	151	296
Cash and cash equivalents at December 31	177	123	151
Cash received (paid) for:
Interest, net of amounts capitalized	(726)	(684)	(633)
Income taxes, net	231	77	501
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	248	224	217
Capital expenditures financed through accounts payable	403	440	339
Noncash common stock issuances	20	21	21
Terminated Capital Leases	18	0	71
Pacific Gas And Electric Company [Member]
Cash Flows from Operating Activities
Net income	1,402	862	1,433
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,754	2,611	2,432
Allowance for equity funds used during construction	(112)	(107)	(100)
Deferred income taxes and tax credits, net	1,042	714	731
Charge for disallowed capital	507	407	116
Other	306	263	226
Effect of changes in operating assets and liabilities:
Accounts receivable	(475)	(177)	16
Inventories	(24)	37	(22)
Accounts payable	179	(2)	(55)
Income taxes receivable/payable	(29)	38	395
Other current assets and liabilities	112	(315)	168
Regulatory assets, liabilities, and balancing accounts, net	(1,214)	(244)	(1,642)
Other noncurrent assets and liabilities	(219)	(340)	(66)
Net cash provided by operating activities	4,344	3,747	3,632
Cash Flows from Investing Activities
Capital expenditures	(5,709)	(5,173)	(4,833)
Decrease in restricted cash	227	64	3
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,295	1,268	1,336
Purchases of nuclear decommissioning trust investments	(1,352)	(1,392)	(1,334)
Other	13	22	29
Net cash used in investing activities	(5,526)	(5,211)	(4,799)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $6, $3, and $2 at respective dates	(9)	683	(583)
Short-term debt financing	500	0	300
Short-term debt matured	0	(300)	0
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of (for PG&E Corporaiton $17, $27, and $17 and for the Utility $17, $27, and $17, at respective dates)	983	1,123	1,961
Repayments of long-term debt	(160)	0	(539)
Preferred stock dividends paid	(14)	(14)	(14)
Common stock dividends paid	(911)	(716)	(716)
Equity contribution from PG&E Corporation	835	705	705
Other	(30)	(13)	43
Net cash provided by (used in) financing activities	1,194	1,468	1,157
Net change in cash and cash equivalents	12	4	(10)
Cash and cash equivalents at January 1	59	55	65
Cash and cash equivalents at December 31	71	59	55
Cash received (paid) for:
Interest, net of amounts capitalized	(717)	(675)	(618)
Income taxes, net	244	77	500
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	403	440	339
Terminated Capital Leases	$ 18	$ 0	$ 71

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Consolidated Statements Of Cash Flows (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flows from Financing Activities
Net issuances of commercial paper, discount	$ 6	$ 3	$ 2
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs	17	27	17
Pacific Gas And Electric Company [Member]
Cash Flows from Financing Activities
Net issuances of commercial paper, discount	6	3	2
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs	$ 17	$ 27	$ 14

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Consolidated Statements Of Equity - USD ($) $ in Millions	Total	Pacific Gas And Electric Company [Member]	Common Stock Shares [Member]	Preferred Stock [Member] Pacific Gas And Electric Company [Member]	Common Stock Amount [Member]	Common Stock Amount [Member] Pacific Gas And Electric Company [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, 2013	$ 14,594			$ 258	$ 9,550	$ 1,322	$ 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			258	10,421	1,322	6,514	5,316	8,130	11	5	15,748	16,229	252
Balance, in shares at Dec. 31, 2014			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			258	11,282	1,322	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
Net income	$ 1,407	$ 1,402						1,407	1,402			1,407	1,402
Other comprehensive income (loss)	(2)	(1)								(2)	(1)	(2)	(1)
Equity contribution from PG&E Corporation		$ 835					835						835
Common stock issued, net	842				842							842
Common stock issued, net, shares			14,866,431
Stock-based compensation amortization	74				74							74
Common stock dividends declared	(972)							(972)	(911)			(972)	(911)
Preferred stock dividend									(14)				(14)
Preferred stock dividend requirement of subsidiary	(14)							(14)				(14)
Balance at Dec. 31, 2016	$ 18,192			$ 258	$ 12,198	$ 1,322	$ 8,050	5,751	8,763	$ (9)	$ 2	17,940	18,395	$ 252
Balance, in shares at Dec. 31, 2016	506,891,874	264,374,809	506,891,874
Cumulative Effect Of New Accounting Principle In Period Of Adoption	$ 29							$ 29	$ 24			$ 29	$ 24

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Organization And Basis Of Presentation

12 Months Ended

Dec. 31, 2016

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 serving 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.  A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations and cash flows during the period in which such change occurred.

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Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

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 or four 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

Prior to October 2016, restricted cash primarily consisted 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)	2016		2015
Electricity generating facilities (1)	5 to 100	$	11,308	$	9,860
Electricity distribution facilities	15 to 55		29,836		28,476
Electricity transmission facilities	15 to 75		11,412		10,196
Natural gas distribution facilities	5 to 60		11,362		10,397
Natural gas transmission and storage facilities	5 to 65		6,491		6,352
Construction work in progress			2,184		2,059
Total property, plant, and equipment			72,593		67,340
Accumulated depreciation			(22,012)		(20,617)
Net property, plant, and equipment		$	50,581	$	46,723

(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 3.73% in 2016, 3.80% in 2015, and 3.77% in 2014.  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 $51 million and $112 million during 2016, $48 million and $107 million during 2015, and $45 million and $100 million during 2014.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2016 and 2015, including nuclear decommissioning obligations:

(in millions)		2016		2015
ARO liability at beginning of year	$	3,643	$	3,575
Revision in estimated cash flows		968		13
Accretion		194		169
Liabilities settled		(121)		(114)
ARO liability at end of year	$	4,684	$	3,643

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.  InMarch2016, the Utility submitted its updated decommissioningcost estimate to the CPUC.  As a result, the estimated undiscounted cost to decommission the Utility’s nuclear power plants increased by approximately $1.4billion. The change in total estimated cost resulted in an $818 million adjustment to theARO. The adjustment was a result of increased estimatedcosts related to spentfuel storage, staffing, and out-of-state waste disposal. 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 recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue untilthose costs are fully recovered. The Utility requested that the CPUC authorize the collection ofincreased annual revenue requirementsbeginning on January 1, 2017 based ontheseupdated cost estimates.

On August 11, 2016, the Utility submitted an application to the CPUC to retire Diablo Canyon at the expiration of its current operating licenses in 2024 (Unit 1) and 2025 (Unit 2). The application includes a joint proposal between the Utility and certain interested parties, entered into on June 20, 2016, which resulted in a $115 million increase to the ARO recognized on the Consolidated Balance Sheets in June 2016.

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 $3.5 billion and $2.5 billion at December 31, 2016 and 2015, respectively.  The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $5.1 billion and $3.5 billion at December 31, 2016 and 2015 (or $7.3 billion in future dollars), respectively. These estimates are based on the 2016 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.  (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, 2016, 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, 2016, 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 herein.

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, 2016 consisted of the following:

	Pension		Other
(in millions, net of income tax)	Benefits		Benefits		Total
Beginning balance	$	(23)	$	16	$	(7)
Other comprehensive income before reclassifications:
Unrecognized prior service cost
(net of taxes of $37 and $15, respectively)		54		(21)		33
Unrecognized net actuarial loss
(net of taxes of $45 and $15, respectively)		(64)		21		(43)
Regulatory account transfer
(net of taxes of $5 and $0, respectively)		7		-		7
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $3 and $6, respectively) (1)		5		9		14
Amortization of net actuarial loss
(net of taxes of $10 and $2, respectively) (1)		14		2		16
Regulatory account transfer
(net of taxes of $13 and $8, respectively) (1)		(18)		(11)		(29)
Net current period other comprehensive loss		(2)		-		(2)
Ending balance	$	(25)	$	16	$	(9)

(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, 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.)

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

Recently Adopted Accounting Guidance

Share-Based Payment Accounting

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718), which amends the existing guidance relating to the accounting for share-based payment awards issued to employees, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.  PG&E Corporation and the Utility have adopted this standard as of the fourth quarter of 2016. 

ASU 2016-09 requires recognition of excess tax benefits and deficiencies in the income statement, which resulted in the recognition of $6.3 millionin income tax benefit for PG&E Corporation and the Utility for the year ended December 31, 2016.  Previously, these amounts were recognized in additional paid-in capital.  Previously unrecognized excess tax benefits were reclassified via a cumulative-effect adjustment.  ASU 2016-09 also requires excess tax benefits and deficiencies to be prospectively excluded from assumed future proceeds in the calculation of diluted shares when calculating diluted earnings per share utilizing the treasury stock method.  The effect of this change on diluted EPS is immaterial.  Additionally, excess income tax benefits from stock-based compensation arrangements are now classified as cash flows from operating activities rather than as cash flows from financing activities, which resulted in an increase to cash flows from operating activities of approximately $7.2 millionfor the year ended December 31, 2016. 

Furthermore, ASU 2016-09 requires, on a retrospective basis, that employee taxes paid for withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities.  As such, the consolidated statements of cash flows for PG&E Corporation and the Utility for the prior periods presented were restated.  This change resulted in an increase to cash flows from operating activities and a decrease to cash flows from financing activities of $34.6 million, $26.8 million, and $13.2 millionfor the years ended December 31, 2016, 2015, and 2014, respectively.

PG&E Corporation and the Utility have elected to continue to estimate forfeitures expected to occur to determine the amount of compensation cost to be recognized in each period and have not changed their policy on statutory withholding requirements and will continue to allow the employee to withhold up to the minimum statutory withholding requirements.

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 standardizes reporting practices related to the fair value hierarchy for all investments for which fair value is measured using net asset value per share.  PG&E Corporation and the Utility adopted this guidance effective January 1, 2016.  The adoption of this standard did not have a material impact on their Consolidated Financial Statements.  All prior periods presented in these Consolidated Financial Statements reflect the retrospective adoption of this guidance.  (See Notes 10 and 11 below.)

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.  PG&E Corporation and the Utility adopted this guidance effective January 1, 2016.  The adoption of this guidance did not have a material impact on their Consolidated Financial Statements.

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 the existing guidance relating to the presentation of debt issuance costs.  The amendments in this ASU 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 adopted this guidance effective January 1, 2016 and applied the requirements retrospectively for all periods presented.  The adoption of this guidance did not have a material impact on their Consolidated Financial Statements.  PG&E Corporation and the Utility restated $105 million and $103 million, respectively, of debt issuance costs as of December 31, 2015 with no impact to net income or total shareholders’ equity previously reported.  All prior periods presented in these Consolidated Financial Statements reflect the retrospective adoption of this guidance.

Accounting Standards Issued But Not Yet Adopted

Restricted Cash

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230), which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows.  The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted.  PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Statements of Cash Flows.

Recognition of Lease Assets and Liabilities

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing guidance relating to the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements.  Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheet, which were previously not recognized.  The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019 with retrospective application.  PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 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 the existing guidance relating to 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.

Revenue Recognition Standard

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance, effective January 1, 2018.  The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdiction, and capital markets and to provide more useful information to users of financial statements through improved disclosure requirements.  PG&E Corporation and the Utility do not plan to early adopt the standard and are currently reviewing all revenue streams and evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.  The Utility does not expect ASU 2014-09 to materially impact the timing or recognition of revenue generated through the sale and delivery of electricity and natural gas to customers.  However, the Utility continues to consider the impacts of outstanding industry-related issues being addressed by the American Institute of CPAs’ Revenue Recognition Working Group and the FASB’s Transition Resource Group.

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Regulatory Assets, Liabilities, And Balancing Accounts

12 Months Ended

Dec. 31, 2016

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)	2016		2015			Period
Pension benefits (1)	$	2,429	$	2,414	Indefinitely(3)
Deferred income taxes(1)		3,859		3,054	47 years
Utility retained generation(2)		364		411	9 years
Environmental compliance costs (1)		778		748	32 years
Price risk management (1)		92		138	10 years
Unamortized loss, net of gain, on reacquired debt (1)		76		94	26 years
Other		353		170	Various
Total long-term regulatory assets	$	7,951	$	7,029

(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) 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, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2016		2015
Cost of removal obligations (1)	$	5,060	$	4,605
Recoveries in excess of AROs (2)		626		631
Public purpose programs(3)		567		600
Other		552		485
Total long-term regulatory liabilities	$	6,805	$	6,321

(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)	2016		2015
Electric distribution	$	132	$	380
Utility generation		48		122
Gas distribution and transmission		541		493
Energy procurement		132		262
Public purpose programs		106		155
Other		541		348
Total regulatory balancing accounts receivable	$	1,500	$	1,760

	Payable
	Balance at December 31,
(in millions)	2016		2015
Gas distribution and transmission	$	48	$	-
Energy procurement		13		112
Public purpose programs		264		244
Other		320		359
Total regulatory balancing accounts payable	$	645	$	715

The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC.  The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case.  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.

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Debt

12 Months Ended

Dec. 31, 2016

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)		2016		2015
PG&E Corporation
Senior notes:
Maturity	Interest Rates
2019	2.40%		350		350
Unamortized discount, net of premium and debt issuance costs			(2)		(2)
Total PG&E Corporation long-term debt			348		348
Utility
Senior notes:
Maturity	Interest Rates
2017	5.625%		700		700
2018	8.25%		800		800
2020	3.50%		800		800
2021	3.25% to 4.25%		550		550
2022 through 2046	2.45% to 6.35%		12,775		11,775
Less: current portion			(700)		-
Unamortized discount, net of premium and debt issuance costs			(161)		(156)
Total senior notes, net of current portion			14,764		14,469
Pollution control bonds:
Maturity	Interest Rates
Series 2004 A-D, due 2023(1)	4.75%		345		345
Series 2009 A-D, due 2026 (2)	variable rate(4)		149		309
Series 1996 C, E, F, 1997 B due 2026(3)	variable rate(5)		614		614
Less: current portion			-		(160)
Total pollution control bonds			1,108		1,108
Total Utility long-term debt, net of current portion			15,872		15,577
Total consolidated long-term debt, net of current portion		$	16,220	$	15,925

(1) The Utility has obtained credit support from an insurance company for these bonds.

(2) Each series of these bonds is supported by a separate direct-pay letter of credit.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent. Series C and D pollution control bonds were redeemed on November 30, 2016.

(3) 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.

(4) At December 31, 2016, the interest rate on these bonds was 0.74%.

(5) At December 31, 2016, the interest rate on these bonds ranged from 0.72% - 0.73%.

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 sales 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.

Repayment Schedule

PG&E Corporation’s and the Utility’s combined long-term debt principal repayment amounts at December 31, 2016 are reflected in the table below:

(in millions,
except interest rates)	2017		2018		2019		2020		2021		Thereafter		Total
PG&E Corporation
Average fixed interest rate		-		-		2.40%		-		-		-		2.40%
Fixed rate obligations	$	-	$	-	$	350	$	-	$	-	$	-	$	350
Utility
Average fixed interest rate		5.625%		8.25%		-		3.50%		3.80%		4.84%		4.94%
Fixed rate obligations	$	700	$	800	$	-	$	800	$	550	$	13,120	$	15,970
Variable interest rate
as of December 31, 2016		-		-		0.74%		0.73%		-		-		0.73%
Variable rate obligations (1)	$	-	$	-	$	149	$	614	$	-	$	-	$	763
Total consolidated debt	$	700	$	800	$	499	$	1,414	$	550	$	13,120	$	17,083

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

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, 2016:

		Credit			Letters of			Commercial
	Termination	Facility			Credit			Paper			Facility
(in millions)	Date	Limit			Outstanding			Outstanding			Availability
PG&E Corporation	April 2021	$	300	(1)		$	-		$	-		$	300
Utility	April 2021		3,000	(2)			41			1,016			1,943
Total revolving credit facilities		$	3,300			$	41		$	1,016		$	2,243

(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 31,2016, PG&E Corporation’s average outstanding commercial paper balance was $84million and the maximum outstanding balance during the year was $176 million.  For 2016, the Utility’s average outstanding commercial paper balance was $837million and the maximum outstanding balance during the year was $1.4 billion.  There were no bank borrowings for PG&E Corporation or the Utility in 2016.

Revolving Credit Facilities

In June 2016, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2020 to April 27, 2021.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 one additional period. 

Borrowings under each credit agreement (other than swingline 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 credit agreement and between 0.8% and 1.275% under the Utility’s credit agreement. The applicable margin for base rate loans will range between 0% and 0.475% under PG&E Corporation’s credit agreement and between 0% and 0.275% under the Utility’s credit agreement.  In addition, the facility fee under PG&E Corporation’s and the Utility’s 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’s and the Utility’s commercial paper programs are used primarily to fund temporary financing needs.  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 2016, the average yield on outstanding PG&E Corporation and Utility commercial paper was 0.63% and 0.64%, respectively.

Other Short-term Borrowings

In March 2016, the Utility entered into a $250 million floating rate unsecured term loan that matures on February 2, 2017.  Additionally, in December 2016, the Utility issued a $250 million unsecured senior floating rate note that matures on November 30, 2017.  The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.

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Common Stock And Share-Based Compensation

12 Months Ended

Dec. 31, 2016

Common Stock And Share-Based Compensation

NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 506,891,874 shares of common stock outstanding at December 31, 2016.  PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2016.

During 2016, PG&E Corporation sold 2.6 million shares of common stock under the February 2015 equity distribution agreement for cash proceeds of $149 million, net of commissions paid of $1.3 million. As of December 31, 2016, the remaining gross sales available under this agreement were $275 million.

In August 2016, PG&E Corporation sold 4.9 million shares of its common stock in an underwritten public offering for net cash proceeds of $309 million.

In addition, during 2016, PG&E Corporation sold 7.4 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 $364 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 the first quarter of 2016, the Board of Directors of PG&E Corporation declared a common stock dividend of $0.455 per share.  In May 2016, the Board of Directors of PG&E Corporation adopted a new quarterly common stock dividend of $0.49 per share. In 2016, total dividends were $1.925 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%.  Additionally, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on a weighted average over five years.  At December 31, 2016, the Utility had restricted net assets of $15.8 billion and was limited to $25 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.  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 13,826,995 shares were available for future awards at December 31, 2016.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2016, 2015, and 2014:

(in millions)	2016		2015		2014
Restricted stock units	$	53	$	47	$	42
Performance shares		55		46		36
Total compensation expense (pre-tax)	$	108	$	93	$	78
Total compensation expense (after-tax)	$	64	$	55	$	47

The amount of share-based compensation costs capitalized during 2016, 2015, and 2014 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 after 2014 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 2016, 2015, and 2014 was $56.68, $53.30, and $43.76, respectively.  The total fair value of restricted stock units that vested during 2016, 2015, and 2014 was $36million, $57 million, and $34 million, respectively.  The tax benefit from restricted stock units that vested during each period was not material.  In general, forfeitures are recorded rateably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2016, $37 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.22years.

The following table summarizes restricted stock unit activity for 2016:

	Number of	Weighted Average Grant-
	Restricted Stock Units	Date Fair Value
Nonvested at January 1	1,972,899	$	47.33
Granted	776,312	$	56.68
Vested	(770,968)	$	46.79
Forfeited	(55,233)	$	49.65
Nonvested at December 31	1,923,010	$	51.26

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 either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period or, for a small number of awards, an internal PG&E Corporation metric.  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 for the total shareholder return based awards or the grant-date market value of PG&E Corporation common stock for internal metric based awards.  The weighted average grant-date fair value for performance shares granted during2016, 2015, and 2014 was $53.61, $68.27, and $51.81 respectively.  There was no tax benefit associated with performance shares during each of these periods.  In general, forfeitures are recorded rateably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2016, $40 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.57 years.

The following table summarizes activity for performance shares in 2016:

	Number of	Weighted Average Grant-
	Performance Shares	Date Fair Value
Nonvested at January 1	1,450,612	$	59.24
Granted	1,233,884		53.61
Vested	(777,719)		51.81
Forfeited (1)	(67,922)		58.20
Nonvested at December 31	1,838,855	$	58.65
(1)Includes performance shares that expired with zero value as performance targets were not met.

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Preferred Stock

12 Months Ended

Dec. 31, 2016

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, 2016 and December 31, 2015, 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, 2016, 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, 2016, 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 2016, 2015, and 2014.

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Earnings Per Share

12 Months Ended

Dec. 31, 2016

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 2016, 2015, and 2014.

	Year Ended December 31,
(in millions, except per share amounts)	2016		2015		2014
Income available for common shareholders	$	1,393	$	874	$	1,436
Weighted average common shares outstanding, basic		499		484		468
Add incremental shares from assumed conversions:
Employee share-based compensation		2		3		2
Weighted average common share outstanding, diluted		501		487		470
Total earnings per common share, diluted	$	2.78	$	1.79	$	3.06

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, 2016

Income Taxes

NOTE 8: INCOME TAXES

PG&E Corporation and the Utility use the asset and 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)	2016		2015			2014			2016				2015			2014
Current:
Federal	$	(105)		$	(89)		$	(84)			$	(105)		$	(88)		$	(84)
State		(70)			11			(41)				(66)			6			(29)
Deferred:
Federal		218			131			396				229			136			426
State		16			(76)			78				16			(69)			75
Tax credits		(4)			(4)			(4)				(4)			(4)			(4)
Income tax provision (benefit)	$	55		$	(27)		$	345			$	70		$	(19)		$	384

The following table describes net deferred income tax liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2016		2015			2016		2015
Deferred income tax assets:
Tax carryforwards		1,851		1,703			1,596		1,462
Other(1)		463		757			402		700
Total deferred income tax assets	$	2,314	$	2,460		$	1,998	$	2,162
Deferred income tax liabilities:
Property related basis differences		10,429		9,656			10,411		9,638
Income tax regulatory asset (2)		1,572		1,244			1,572		1,245
Other(3)		526		766			525		766
Total deferred income tax liabilities	$	12,527	$	11,666		$	12,508	$	11,649
Total net deferred income tax liabilities	$	10,213	$	9,206		$	10,510	$	9,487

(1)Amounts include compensation and benefits, environmental reserve, and customer advances for construction. 

(2)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 of the Notes to the Consolidated Financial Statements in Item 8.)

(3)Amounts primarily relate to regulatory balancing accounts.  Greenhouse gas allowances are temporary timing differences that reverse through regulatory balancing accounts. 

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,
	2016			2015			2014			2016				2015			2014
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)	(2.5)		(4.9)			1.4			(2.2)				(4.8)			1.6
Effect of regulatory treatment
of fixed asset differences (2)	(23.7)		(33.6)			(15.0)			(23.4)				(33.7)			(14.7)
Tax credits	(0.8)		(1.3)			(0.7)			(0.8)				(1.3)			(0.7)
Benefit of loss carryback	(1.1)		(1.5)			(0.8)			(1.1)				(1.5)			(0.8)
Non deductible penalties (3)	0.8		4.3			0.3			0.8				4.3			0.3
Other, net(4)	(3.9)		(1.1)			(0.8)			(3.5)				(0.2)			0.4
Effective tax rate	3.8	%	(3.1)		%	19.4		%	4.8			%	(2.2)		%	21.1		%

(1)Includes the effect of state flow-through ratemaking treatment.  In 2016 and 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 as authorized by the 2014 GRC decision in all periods presented and by the 2015 GT&S decision which impacts only 2016.  All amounts are impacted by the level of income before income taxes.  The 2014 GRC and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. 

(3) Primarily represents the effects of non-tax deductible fines and penalties associated with the natural gas distribution facilities record-keeping decision for the year ended December 31, 2016 and the effects of the Penalty Decision for the year ended December 31, 2015.  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.

(4) In 2016, the amount primarily represents the impact of tax audit settlements.

Unrecognized tax benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation						Utility
(in millions)	2016		2015		2014		2016		2015		2014
Balance at beginning of year	$	468	$	713	$	666	$	462	$	707	$	660
Additions for tax position taken
during a prior year		-		40		7		-		40		7
Reductions for tax position
taken during a prior year		(77)		(349)		(9)		(77)		(349)		(9)
Additions for tax position
taken during the current year		56		64		61		56		64		61
Settlements		(59)		-		(12)		(59)		-		(12)
Balance at end of year	$	388	$	468	$	713	$	382	$	462	$	707

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2016 for PG&E Corporation and the Utility was $25 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, 2016, it is reasonably possible that unrecognized tax benefits will decrease by approximately $70 million within the next 12 months.  PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income.

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, 2016, 2015, and 2014, these amounts were immaterial.

IRS settlements

PG&E Corporation previously participated in the Compliance Assurance Process, 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 participation in the Compliance Assurance Process ended effective with the submission of its 2015 tax return.

PG&E Corporation’s tax returns have been accepted through 2015 except for a few matters, the most significant of which relates to deductible repair costs.  In March 2016, PG&E Corporation reached an agreement with the IRS on deductible electric transmission and distribution repair costs for the 2012 tax year.  The agreement provided that the methodology used in determining the deductible amount should be followed for all subsequent periods, absent any material change in facts.  Deductible repair costs for other lines of business will continue to be subject to examination by the IRS for subsequent years.  The IRS is expected to issue guidance in 2017 that clarifies which repair costs are deductible for the natural gas transmission and distribution businesses. 

Tax years after 2008 remain subject to examination by the state of California.

2015 Gas Transmission and Storage Rate Case

In comments to the proposed decision in phase two of the 2015 GT&S rate case, the Utility questioned whether the methodology employed to calculate the capital disallowance portion of the San Bruno penalty might constitute a normalization violation.  In recognition of this concern, the CPUC, in the final phase two decision, provided the Utility an opportunity to submit a ruling to the IRS for guidance and establish a memorandum account to track the additional revenue that would be recoverable if the method is deemed to be a normalization violation.  The Utility anticipates filing the ruling request in early 2017.

As a result of the final phase two decision, PG&E Corporation and the Utility applied flow through accounting to property-related timing differences for 2016 and 2015.

Carryforwards

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

	December 31,		Expiration
(in millions)	2016		Year
Federal:
Net operating loss carryforward	$	5,009	2029 - 2036
Tax credit carryforward		116	2029 - 2036
Charitable contribution loss carryforward		192	2017 - 2021
State:
Net operating loss carryforward	$	-	N/A
Tax credit carryforward		51	Various
Charitable contribution loss carryforward		112	2019 - 2021

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, 2016 for these tax attributes.

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Derivatives And Hedging Activities

12 Months Ended

Dec. 31, 2016

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 under the applicable ratemaking mechanism in place as long as 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, 2016 and 2015, respectively, the volumes of the Utility’s outstanding derivatives were as follows:

		Contract Volume
Underlying Product	Instruments	2016	2015
Natural Gas (1)(MMBtus (2))	Forwards and Swaps	323,301,331	333,091,813
	Options	96,602,785	111,550,004
Electricity (Megawatt-hours)	Forwards and Swaps	3,287,397	3,663,512
	Congestion Revenue Rights (3)	278,143,281	216,383,389

(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, 2016, 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	$	91	$	(10)	$	1	$	82
Other noncurrent assets – other		149		(9)		-		140
Current liabilities – other		(48)		10		-		(38)
Noncurrent liabilities – other		(101)		9		3		(89)
Total commodity risk	$	91	$	-	$	4	$	95

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

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

	Commodity Risk
	For the year ended December 31,
(in millions)	2016		2015		2014
Unrealized gain/(loss) - regulatory assets and liabilities (1)	$	64	$	(6)	$	124
Realized loss - cost of electricity (2)		(53)		(14)		(83)
Realized loss - cost of natural gas (2)		(18)		(10)		(8)
Total commodity risk	$	(7)	$	(30)	$	33

(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, 2016, 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)	2016		2015
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(24)	$	(2)
Related derivatives in an asset position		19		-
Collateral posting in the normal course of business related to
these derivatives		4		-
Net position of derivative contracts/additional collateral
posting requirements(1)	$	(1)	$	(2)

(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, 2016

Fair Value Measurements

NOTE 10: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets and price risk management instruments 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 are held by PG&E Corporation and not the Utility.

	Fair Value Measurements
	At December 31, 2016
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	105	$	-	$	-	$	-	$	105
Nuclear decommissioning trusts
Short-term investments		9		-		-		-		9
Global equity securities		1,724		-		-		-		1,724
Fixed-income securities		665		527		-		-		1,192
Assets measured at NAV		-		-		-		-		14
Total nuclear decommissioning trusts (2)		2,398		527		-		-		2,939
Price risk management instruments
(Note 9)
Electricity		30		18		181		(18)		211
Gas		-		11		-		-		11
Total price risk management		30		29		181		(18)		222
instruments
Rabbi trusts
Fixed-income securities		-		61		-		-		61
Life insurance contracts		-		70		-		-		70
Total rabbi trusts		-		131		-		-		131
Long-term disability trust
Short-term investments		8		-		-		-		8
Assets measured at NAV		-		-		-		-		170
Total long-term disability trust		8		-		-		-		178
TOTAL ASSETS	$	2,541	$	687	$	181	$	(18)	$	3,575
Liabilities:
Price risk management instruments
(Note 9)
Electricity	$	9	$	12	$	126	$	(21)	$	126
Gas		-		2		-		(1)		1
TOTAL LIABILITIES	$	9	$	14	$	126	$	(22)	$	127

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

(2) Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	64	$	-	$	-	$	-	$	64
Nuclear decommissioning trusts
Short-term investments		36		-		-		-		36
Global equity securities		1,520		-		-		-		1,520
Fixed-income securities		694		521		-		-		1,215
Assets measured at NAV		-		-		-		-		13
Total nuclear decommissioning trusts (2)		2,250		521		-		-		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
Short-term investments		7		-		-		-		7
Assets measured at NAV		-		-		-		-		158
Total long-term disability trust		7		-		-		-		165
TOTAL ASSETS	$	2,321	$	658	$	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.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.  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 years ended December 31, 2016 and 2015.

Trust Assets

In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1. 

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.

Fixed-income 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.

On January 1, 2016, PG&E Corporation and the Utility adopted FASB 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) and applied it retrospectively for the periods presented in their Consolidated Financial Statements. (See Note 2 above.) In accordance with this guidance, investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities.  There are no restrictions on the terms and conditions upon which the investments may be redeemed. 

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 Financial Officer, 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, 2016					Valuation		Unobservable
Fair Value Measurement	Assets		Liabilities		Technique		Input		Range (1)
Congestion revenue rights	$	181	$	35	Market approach		CRR auction prices		$	(11.88) - 6.93
Power purchase agreements	$	-	$	91	Discounted cash flow		Forward prices		$	18.07 - 38.80

1. Represents price per megawatt-hour

	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

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2016 and 2015, respectively:

	Price Risk Management Instruments
(in millions)	2016			2015
Asset (liability) balance as of January 1	$	89	$		69
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(34)			20
Asset (liability) balance as of December 31	$	55	$		89

(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, 2016 and 2015, 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, 2016 and 2015.

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,
	2016					2015
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount			Level 2 Fair Value
Debt (Note 4)
PG&E Corporation	$	348	$	352	$		348	$	354
Utility		15,813		17,790			14,818		16,422

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, 2016
Nuclear decommissioning trusts
Short-term investments	$	9	$	-	$	-	$	9
Global equity securities		584		1,157		(3)		1,738
Fixed-income securities		1,156		48		(12)		1,192
Total (1)	$	1,749	$	1,205	$	(15)	$	2,939
As of December 31, 2015
Nuclear decommissioning trusts
Short-term 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

(1) Represents amounts before deducting $333 million and $314 million at December 31, 2016 and 2015, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of fixed-income securities by contractual maturity is as follows:

	As of
(in millions)	December 31, 2016
Less than 1 year	$	13
1–5 years		419
5–10 years		255
More than 10 years		505
Total maturities of fixed-income securities	$	1,192

The following table provides a summary of activity for the fixed-income and equity securities:

	2016		2015		2014
(in millions)
Proceeds from sales and maturities of nuclear decommissioning
investments	$	1,295	$	1,268	$	1,336
Gross realized gains on securities held as available-for-sale		18		55		118
Gross realized losses on securities held as available-for-sale		(26)		(37)		(12)

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2016

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 2016 and 2015:

Pension Plan

(in millions)	2016		2015
Change in plan assets:
Fair value of plan assets at beginning of year	$	13,745		$	14,216
Actual return on plan assets		1,358			(176)
Company contributions		334			334
Benefits and expenses paid		(708)			(629)
Fair value of plan assets at end of year	$	14,729		$	13,745
Change in benefit obligation:
Benefit obligation at beginning of year	$	16,299		$	16,696
Service cost for benefits earned		453			479
Interest cost		715			673
Actuarial (gain) loss		637			(922)
Plan amendments		(91)			1
Transitional costs		-			1
Benefits and expenses paid		(708)			(629)
Benefit obligation at end of year (1)	$	17,305		$	16,299
Funded Status:
Current liability	$	(7)		$	(6)
Noncurrent liability		(2,569)			(2,547)
Net liability at end of year	$	(2,576)		$	(2,553)

(1) PG&E Corporation’s accumulated benefit obligation was $15.6 billion and $14.7 billion at December 31, 2016 and 2015, respectively.

Postretirement Benefits Other than Pensions

(in millions)	2016		2015
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,035		$	2,092
Actual return on plan assets		167			(26)
Company contributions		52			61
Plan participant contribution		85			68
Benefits and expenses paid		(166)			(160)
Fair value of plan assets at end of year	$	2,173		$	2,035
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,766		$	1,811
Service cost for benefits earned		52			55
Interest cost		76			71
Actuarial (gain) loss		11			(98)
Plan amendments		37			-
Transitional costs		-			1
Benefits and expenses paid		(153)			(146)
Federal subsidy on benefits paid		3			4
Plan participant contributions		85			68
Benefit obligation at end of year	$	1,877		$	1,766
Funded Status: (1)
Noncurrent asset	$	368		$	344
Noncurrent liability		(72)			(75)
Net asset at end of year	$	296		$	269

(1) At December 31, 2016 and 2015, 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)	2016		2015			2014
Service cost	$	453		$	479		$	383
Interest cost		715			673			695
Expected return on plan assets		(828)			(873)			(807)
Amortization of prior service cost		8			15			20
Amortization of net actuarial loss		24			10			2
Net periodic benefit cost		372			304			293
Less: transfer to regulatory account (1)		(34)			34			42
Total expense recognized	$	338		$	338		$	335

(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)	2016		2015			2014
Service cost	$	52		$	55		$	45
Interest cost		76			71			76
Expected return on plan assets		(107)			(112)			(103)
Amortization of prior service cost		15			19			23
Amortization of net actuarial loss		4			4			2
Net periodic benefit cost	$	40		$	37		$	43

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 2017 are as follows:

(in millions)	Pension Plan		PBOP Plans
Unrecognized prior service cost	$	(7)	$	15
Unrecognized net loss		22		4
Total	$	15	$	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,
	2016		2015		2014		2016		2015		2014
Discount rate	4.11	%	4.37	%	4.00	%	4.05 - 4.19	%	4.27 - 4.48	%	3.89 - 4.09	%
Rate of future compensation
increases	4.00	%	4.00	%	4.00	%	-		-		-
Expected return on plan
assets	5.30	%	6.10	%	6.20	%	2.80 - 6.00	%	3.20 - 6.60	%	3.30 - 6.70	%

The assumed health care cost trend rate as of December 31, 2016 was 7.2%, decreasing gradually to an ultimate trend rate in 2025 and beyond of approximately 4.5%.  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	$	118	$	(120)
Effect on service and interest cost		9		(10)

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets.  Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate.  Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added to a long-term inflation rate.  For the pension plan, the assumed return of 5.3% compares to a ten-year actual return of 7.3%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 696 Aa-grade non-callable bonds at December 31, 2016.  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, global REITS, global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios.

In the Pension Plan, target allocations for 2017 were updated to reflect a 2% increase in global equity investments and a 2% decrease in fixed income investments. Target allocations for PBOP Plans remain unchanged. Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are 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
	2017		2016			2015			2017			2016			2015
Global equity	27	%		25	%		25	%		32	%		32	%		31	%
Absolute return	5	%		5	%		5	%		3	%		3	%		3	%
Real assets	10	%		10	%		10	%		7	%		7	%		8	%
Fixed income	58	%		60	%		60	%		58	%		58	%		58	%
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, 2016 and 2015. 

	Fair Value Measurements
	At December 31,
	2016												2015
(in millions)	Level 1			Level 2			Level 3			Total				Level 1			Level 2			Level 3			Total
Pension Plan:
Short-term investments	$	364	$		369	$		-	$		733	$			247	$		375	$		-	$		622
Global equity		996			-			-			996				903			-			-			903
Real assets		610			-			-			610				581			-			-			581
Fixed-income		1,754			4,774			5			6,533				1,841			4,495			3			6,339
Assets measured at NAV		-			-			-			5,950				-			-			-			5,308
Total	$	3,724	$		5,143	$		5	$		14,822	$			3,572	$		4,870	$		3	$		13,753
PBOP Plans:
Short-term investments	$	33	$		-	$		-	$		33	$			20	$		-	$		-	$		20
Global equity		115			-			-			115				104			-			-			104
Real assets		70			-			-			70				69			-			-			69
Fixed-income		150			656			-			806				150			632			-			782
Assets measured at NAV		-			-			-			1,153				-			-			-			1,065
Total	$	368	$		656	$		-	$		2,177	$			343	$		632	$		-	$		2,040
Total plan assets at fair value									$		16,999											$		15,793

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $97 million and $13 million at December 31, 2016 and 2015, 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 and equity-index futures.  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.

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. 

Fixed-Income

Fixed-incomesecurities 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.

Assets Measured at NAV

On January 1, 2016, PG&E Corporation and the Utility adopted FASB 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) and applied it retrospectively for the periods presented in their Consolidated Financial Statements.  (See Note 2 above.)  In accordance with this guidance, investments in the pension and PBOP plans that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above.  The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets.  These investments include commingled funds that are composed of equity securities traded publicly on exchanges, hedge funds, private real estate funds, and fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities.

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, 2016 and 2015.

Level 3 Reconciliation

The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2016 and 2015:

(in millions)	Fixed-
For the year ended December 31, 2016	Income
Balance at beginning of year	$	3
Actual return on plan assets:
Relating to assets still held at the reporting date		3
Relating to assets sold during the period		-
Purchases, issuances, sales, and settlements:
Purchases		-
Settlements		(1)
Balance at end of year	$	5
(in millions)	Fixed-
For the year ended December 31, 2015	Income
Balance at beginning of year	$	12
Actual return on plan assets:
Relating to assets still held at the reporting date		(3)
Relating to assets sold during the period		1
Purchases, issuances, sales, and settlements:
Purchases		2
Settlements		(9)
Balance at end of year	$	3

There were no material transfers out of Level 3 in 2016 and 2015.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $334 million to the pension benefit plans and $52 million to the other benefit plans in 2016.  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 2016.  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 2017.

Benefits Payments and Receipts

As of December 31, 2016, 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
2017	$	739	$	87	$	(8)
2018		781		93		(9)
2019		821		97		(10)
2020		857		103		(10)
2021		892		108		(11)
Thereafter in the succeeding five years		4,879		592		(15)

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 $97 million, $89 million, and $80 million in 2016, 2015, and 2014, 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, 2016

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)	2016		2015		2014
Utility revenues from:
Administrative services provided to PG&E Corporation	$	7	$	6	$	5
Utility expenses from:
Administrative services received from PG&E Corporation	$	74	$	53	$	54
Utility employee benefit due to PG&E Corporation		91		82		70

At December 31, 2016 and 2015, the Utility had receivables of $18 million and $22 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 $22 million and $21 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, 2016

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.  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.  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.  PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters.

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 occurred 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 CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices.

On October 14, 2016, the Cities of San Bruno and San Carlos, ORA, the SED, TURN, and the Utility submitted a status report to the CPUC which proposed an update to the framework for resolving the proceeding.  The revised framework includes a total of 164 communications in the scope of the proceeding.  Throughout 2016, the parties jointly submitted stipulations on all of the communications, and on November 30, 2016, the parties began settlement discussions.  In the event a settlement cannot be reached, the parties will brief the matter based upon the identified communications and some related discovery as well as factual stipulations and agreed upon issues of policy and law for CPUC resolution.  The opening briefs are due on March 24, 2017, and reply briefs are due on April 14, 2017.

The Utility expects that the other parties may argue that the number of violations exceeds the 164 communications referenced in the October 14, 2016 joint status report either because a single communication may have violated more than one rule or because they believe some of the material provided during discovery constitutes impermissible ex parte communications.  The Utility expects to contest many of these assertions.  If the matter does not settle, the CPUC will determine which communications included within the scope of the proceeding were in violation of its rules.  The CPUC will also determine whether to impose penalties or other remedies, as a result of a potential settlement or otherwise.  The CPUC can impose fines up to $50,000 for each violation, and up to $50,000 per day if the CPUC determines that the violation was continuing.  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 broad discretion in determining whether violations are continuing and the amount of penalties to be imposed. 

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the OII.  In light of recent CPUC decisions, such as the Penalty Decision and the decision in the 2015 GT&S rate case, the Utility expects that such penalties could include fines and future revenue requirement reductions.  In accordance with accounting rules, revenue requirement reductions would be recorded in the period they are incurred and fines would be recorded when considered probable and their amount or range can be reasonably estimated.  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 because it is uncertain how the CPUC will calculate the number of violations or the penalty for any violations.

Finally, in 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel.  The Utility has cooperated with those investigations.  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 required 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 cited 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.  

On August 18, 2016, the CPUC approved a final decision in this investigation.  The CPUC assessed a fine of $25.6 million.  With the $10.85 million citation previously paid in 2015 for the City of Carmel-by-the-Sea (“Carmel”) incident, the total fine imposed on the Utility was $36.5 million.  The remaining $25.6 million was paid in September 2016.  The decision denied the appeals previously filed by the SED and Carmel from the presiding officer’s decision, and closed this proceeding but allowed the parties an opportunity to request that this proceeding be reopened if needed to ensure proper implementation of a compliance plan to be developed by the parties. 

On September 26, 2016, the SED filed an application for rehearing of the CPUC’s decision.  Specifically, the application indicates that the CPUC erred in certain of its determinations (including those related to maximum allowable operating pressure documentation that, if adopted, could result in an additional fine of $7 million), calculations (including those related to the missing De Anza records violations) and certain other findings, and requests that the CPUC adopt its recommendations.  On October 11, 2016, the Utility submitted its response to the CPUC in which it opposed the SED’s application for rehearing arguing that the application failed to identify a legal error warranting rehearing by the CPUC.  The Utility cannot predict when or if the CPUC will grant the rehearing or if it will adopt the SED’s recommendations.

On October 24, 2016 and November 30, 2016, the Utility held meet and confer sessions with parties to develop remedial measures necessary to address the issues identified in the CPUC decision with the objective of establishing a compliance plan.  On December 16, 2016, the Utility submitted its Initial Gas Distribution Records Compliance Plan that includes feasible and cost-effective measures necessary to improve natural gas distribution system record-keeping. 

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 had been completed and that remediation work, including removal of the encroachments, was 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 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.  The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports.  Under both the gas and electric programs, the SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000.  The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day.  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.  There is also an administrative limit of $8 million per citation issued.

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 penalties or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations, based on the SED’s investigations of incidents reported to the CPUC, or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits or investigations.  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 and other CPUC staff has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.

In September 2016, the Utility reported that it discovered in November 2015 that approximately 550,000 atmospheric corrosion inspections on above-ground gas distribution meters completed in 2014, which constituted 35% of such inspections in 2014, were performed by non-operator qualified personnel.  The Utility did not provide timely notification of such non-compliance to the CPUC.  On December 23, 2016, the SED issued the Utility a citation with a $5.45 million fine related to this self-report.  The citation included a $5.05 million fine for not ensuring that contractor inspectors were operator-qualified, a $350,000 fine for not completing inspections within 39 months from the previous inspections, and a $50,000 fine for not reporting the self-identified violations within ten days of discovery.  The amount of the fine is conditioned upon the Utility implementing certain remedial measures.  The Utility paid the fine in January 2017.

In February 2017, the Utility reported that it discovered in April 2014 that customer service representatives who handle gas emergency calls within the Utility’s call centers are not included in the drug and alcohol testing program as required by PHMSA regulations.  The Utility did not provide timely notification of such non-compliance to the CPUC.  The SED could impose fines on the Utility of $50,000 per violation, and also for failure to timely file a self-report in connection with the non-compliance.  The SED has the authority to issue more than one citation for a series of related incidents and can impose daily fines for continuing violations, and the CPUC can issue an OII and possible additional fines even after the SED has issued a citation.  The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines that could be imposed with respect to this self-report, for the reasons indicated above, or to predict whether the CPUC will open a formal proceeding. 

Federal Matters

Federal Criminal Trial

On June 14, 2016, a federal criminal trial against the Utility began in the United States District Court for the Northern District of California, in San Francisco, on 12 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, and one felony count charging that the Utility obstructed the NTSB investigation into the cause of the San Bruno accident.  On July 26, 2016, the court granted the government’s motion to dismiss one count alleging that the Utility knowingly and willfully failed to retain a strength test pressure record with respect to a distribution feeder main, thereby reducing the total number of counts from 13 to 12.

On August 9, 2016, the jury returned its verdict.  The jury acquitted the Utility on all six of the record-keeping allegations but found the Utility guilty on six felony counts that include one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act.

On January 26, 2017, the court issued a judgment of conviction sentencing the Utility to a five-year corporate probation period, oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service.  The Utility has decided not to appeal the convictions.  The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period.  As part of the probation, the Utility is required to retain a third-party monitor.  The goal of the monitorship will be to prevent the criminal conduct with respect to gas pipeline transmission safety that gave rise to the conviction.  To that end, the goal of the monitor will be to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of the gas transmission pipeline system, performs appropriate integrity management assessments on its gas transmission pipelines, and maintains an effective ethics and compliance program and safety related incentive program.

After an initial assessment is conducted and an initial report is prepared by the monitor, the monitor will prepare reports on a semi-annual basis setting forth the monitor’s continued assessment and making recommendations consistent with the goals and scope of the monitorship.  The Utility expects that the monitor will be retained before the end of the second quarter of 2017. 

At December 31, 2016, PG&E Corporation’s and the Utility’s Consolidated Balance Sheets include a $3 million accrual in connection with this matter.  On February 1, 2017, the Utility paid the $3 million fine imposed by the court.  The Utility could incur material costs, not recoverable through rates, in the event of non-compliance with the terms of probation and in connection with the monitorship (including but not limited to the monitor’s compensation or costs resulting from recommendations of the monitor).

Other Federal Matters

In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel.  The Utility has cooperated with those investigations.  In addition, in October 2016, the Utility received a grand jury subpoena and letter from the U.S. Attorney for the Northern District of California advising that the Utility is a target of a federal investigation regarding possible criminal violations of the Migratory Bird Treaty Act and conspiracy to violate the act.  The investigation involves a removal by the Utility of a hazardous tree that contained an osprey nest and egg in Inverness, California, on March 18, 2016.  It is uncertain whether any charges will be brought against the Utility as a result of these investigations.

Other Matters

Butte Fire Litigation

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California.  On April 28, 2016, Cal Firereleased its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures.  Cal Fire’sreport concluded that the wildfire was caused when a Gray Pine tree contactedthe Utility’selectric line which ignited portions of the tree, and determined that the failure by the Utilityand/or its vegetation management contractors, ACRT Inc. and Trees, Inc.,to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. In a press release also issued on April 28, 2016, Cal Fire indicated that it will seek to recover firefighting costs in excess of $90 million from the Utility.

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California for Sacramento County. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council had previously authorized the coordination of all cases in Sacramento County. As of December 31, 2016, complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 1,950 individual plaintiffs representing approximately 950 households and their insurance companies. These complaints are part of or are in the process of being added to the two master complaints.Plaintiffs seek to recover damages and other costs, principally based on inverse condemnation and negligence theories of liability.  The number of individual complaints and plaintiffs may increase in the future. 

The Utility continues mediating and settling cases.  The next case management conference is scheduled for March 2, 2017.

In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees without having been found negligent, through the theory of inverse condemnation.  In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent.  The Utility believes it was not negligent; however, there can be no assurance that a court or jury would agree with the Utility.  The Utility believes that it is probable that it will incur a loss of at least $750 million for all potential damages described above.  This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and other damages that the Utility could be liable for under the theories of inverse condemnation and/or negligence.

The following table presents changes in the third-party claims liability since December 31, 2015.  The balance for the third-party claims liability is included in Other current liabilities in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Loss Accrual  (in millions)
Balance at December 31, 2015	$	-
Accrued losses		750
Payments		(60)
Balance at December 31, 2016	$	690

In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $27 million.

The Utility believes that it is reasonably possible that it will incur losses related to Butte fire claims in excess of $750 million accrued through December 31, 2016 but is currently unable to reasonably estimate the upper end of the range of losses because it is still in an early stage of the evaluation of claims, the mediation and settlement process, and discovery.  The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors.  As more information becomes known, including additional discovery from the plaintiffs and results from the ongoing mediation and settlement process, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued. 

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of approximately $900 million.  The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range.  The Utility has recorded $625 million for probable insurance recoveries in connection with losses related to the Butte fire.  While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.  In addition, the Utility is pursuing coverage under the insurance policies of its two vegetation management contractors, including under policies where the Utility is listed as an additional insured.  Recoveries of any amounts under these policies are uncertain.

The following table presents changes in the insurance receivable since December 31, 2015.  The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Insurance Receivable (in millions)
Balance at December 31, 2015	$	-
Accrued insurance recoveries		625
Reimbursements		(50)
Balance at December 31, 2016	$	575

If the Utility records losses in connection with claims relating to the Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected in the reporting periods during which additional charges are recorded, depending on whether the Utility is able to record or collect insurance recoveries in amounts sufficient to offset such additional accruals.

Other Contingencies

PG&E Corporation and the Utility are subject to various claims, lawsuits and regulatory proceedings that separately are not considered material.  Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $45 million at December 31, 2016 and $63 million at December 31, 2015.  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. 

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 and the amount of disallowance can be reasonably estimated.  Capital disallowances are reflected in operating and maintenance expenses in the Consolidated Statements of Income.  Disallowances as a result of the CPUC’s June 23, 2016 final phase one decision and December 1, 2016 final phase two decision in the Utility’s 2015 GT&S rate case, the April 9, 2015 Penalty Decision and the Utility’s Pipeline Safety Enhancement Plan are discussed below.

2015 GT&S Rate Case Disallowance of Capital Expenditures

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The decision permanently disallowed a portion of the 2011 through 2014 capital spending in excess of the amount adopted and established various cost caps that will increase the risk of overspend over the current rate case cycle, including new one-way capital balancing accounts.  As a result, in 2016, the Utility incurred charges of $219 million for capital expenditures that the Utility believes are probable of disallowance based on the decision. This included $134 million to the net plant balance for 2011 through 2014 capital expenditures in excess of adopted amounts and $85 million for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts.  Additional charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending.

Penalty Decision’s Disallowance of Natural Gas Capital Expenditures

On April 9, 2015, the CPUC issued a decision in its investigative enforcement proceedings against the Utility to impose total penalties of $1.6 billion on the Utility after determining that the Utility had committed numerous violations of laws and regulations related to its natural gas transmission operations (the “Penalty Decision”).  In January 2016, the CPUC closed the investigative proceedings.  The total penalty includes (1) a $300 million fine, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million.

On December 1, 2016, the CPUC approved a final phase two decision in the Utility’s 2015 GT&S rate case, which applies $689 million of the $850 million penalty to capital expenditures.  The decision also approves the Utility’s list of programs and projects that meet the CPUC’s definition of “safety related,” the costs of which are to be funded through the $850 million penalty.

For the twelve months ended December 31, 2016, the Utility recorded charges for disallowed capital spending of $283 million as a result of the Penalty Decision.  The cumulative charges at December 31, 2016, and the additional future charges that will be recognized in the first quarter of 2017 are shown in the following table:

	Twelve Months		Cumulative		Future
	Ended		Charges		Charges
		December 31,		December 31,	and		Total
(in millions)	2016		2016		Costs		Amount
Fine paid to the state	$	-	$	300	$	-	$	300
Customer bill credit paid		-		400		-		400
Charge for disallowed capital (1)		283		689		-		689
Disallowed revenue for pipeline safety
expenses (2)		129		129		32		161
CPUC estimated cost of other remedies (3)		-		-		-		50
Total Penalty Decision fines and remedies	$	412	$	1,518	$	32	$	1,600

(1) The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs.  On December 1, 2016, the CPUC approved a final phase two decision in the Utility’s 2015 GT&S rate case which allocates $689 million of the $850 million penalty to capital expenditures.

(2) GT&S revenues have been reduced for these unrecovered expenses. The remaining charges will be recognized in the first quarter of 2017.

(3)In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision.  This table does not reflect the Utility’s remedy-related costs already incurred or the Utility’s estimated future remedy-related costs.

Capital Expenditures Relating to Pipeline Safety Enhancement Plan

The CPUC has authorized the Utility to collect $766 million for recovery of PSEP capital costs.  As of December 31, 2016, the Utility has spent $1.35 billion on PSEP-related capital costs, of which $665 million was expensed in previous years for costs that are expected to exceed the authorized amount.  The Utility expects the remaining PSEP work to continue beyond 2017.  The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected.

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
	December 31		December 31,
(in millions)	2016		2015
Topock natural gas compressor station (1)	$	299	$	300
Hinkley natural gas compressor station (1)		135		140
Former manufactured gas plant sites owned by the Utility or third parties		285		271
Utility-owned generation facilities (other than fossil fuel-fired),   other facilities, and third-party disposal sites		131		164
Fossil fuel-fired generation facilities and sites		108		94
Total environmental remediation liability	$	958	$	969

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

The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the EPA under the federal Resource Conversation and Recovery Act as well as other state hazardous waste laws.  The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements.  The Utility assesses and monitors, on an ongoing basis, measures that may be necessary to comply with these laws and regulations and implements changes to its program as deemed appropriate.  The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability at December 31, 2016 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 implement final remediation plans 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.

At December 31, 2016 the Utility expected to recover $671 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 Needles, California and is referred to below as the “Topock site.”  Another station is located near Hinkley, California and is referred to below as the “Hinkley site.” The Utility is also required to take measures to abate the effects of the contamination on the environment.

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the DOI.

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 conducted an additional environmental review of the proposed design and issued a draft environmental impact report for public comment in January 2017.  After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in mid-2017. After the Utility modifies its design in response to the final report, the Utility will seek approval to begin construction of the new in-situ treatment system in late 2017 or early 2018.

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.  In November 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.

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 Topock and Hinkley 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, financial condition and cash flows 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 $3.2 billion per nuclear incident and $2.6 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.

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 $3.2 billion for each insured loss.  In contrast, NEIL would treat all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share the $3.2 billion policy limit amount. 

In addition to the nuclear insurance the Utility maintains through theNEIL, the Utility also is a member of theEMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon.

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, 2016, the current maximum aggregate annual retrospective premium obligation for the Utility would be approximately $60 million.EMANI provides $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies.  If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $2 million, as of December 31, 2016.

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. 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.  In connection with the CPUC approved settlement agreement, on April 12, 2004, the Utility deposited approximately $1.7 billion into escrow for the payment of certain disputed claims, previously collected from customers through rates.  Generally, 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.

On October 13, 2016, the Utility received approval from the bankruptcy court to release the remaining cash held in escrow to unrestricted cash for use by the Utility. The approval resulted in a $161 million reduction to the cash in escrow within the Restricted cash balance on the Consolidated Balance Sheets.

On September 2, 2016, the Utility’s settlement became effective resolving, among other matters, the Utility’s claim against the CAISO for $165 million, which includes receivables and interest. Additionally, the Utility agreed to release $66 million of cash from escrow to the California Power Exchange.  The settlement resulted in a $231 million reduction to the Disputed claims and customer refunds balance on the Consolidated Balance Sheets.    

At December 31, 2016 and December 31, 2015, respectively, the Consolidated Balance Sheets reflected $236 million and $454 million in net claims within Disputed claims and customer refunds.  The cash held in escrow within Restricted cash was zero as of December 31, 2016 and $228 million as of December 31, 2015. The Utility is uncertain when or 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, 2016:

	Power Purchase Agreements
	Renewable		Conventional				Natural		Nuclear
(in millions)	Energy		Energy		Other		Gas		Fuel		Total
2017	$	2,233	$	815	$	369	$	536	$	97	$	4,050
2018		2,108		716		284		169		93		3,370
2019		2,144		698		225		160		95		3,322
2020		2,139		677		179		148		130		3,273
2021		2,117		585		147		93		49		2,991
Thereafter		27,685		1,168		653		455		136		30,097
Total purchase
commitments	$	38,426	$	4,659	$	1,857	$	1,561	$	600	$	47,103

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.  As of December 31, 2016, renewable energy contracts expire at various dates between 2017 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, 2016, these power purchase agreements expire at various dates between 2017 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, 2016 and 2015, net capital leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $35 million and $54 million including accumulated amortization of $148 million and $147 million, respectively.  The present value of the future minimum lease payments due under these agreements included $17 million and $19 million in Current Liabilities and $18 million and $35 million in Noncurrent Liabilities on the Consolidated Balance Sheet, respectively.  As of December 31, 2016, QF contracts in operation expire at various dates between 2017 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 2016, $3.5 billion in 2015, and $3.6 billion in 2014.

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 2017 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 $0.7 billion in 2016, $0.9 billion in 2015, and $1.4 billion in 2014.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2017 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 $100 million in 2016, $128 million in 2015, and $105 million in 2014.

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 2017 and 2052.  At December 31, 2016, the future minimum payments related to these commitments were as follows:

(in millions)	Operating Leases
2017	$	44
2018		41
2019		39
2020		39
2021		36
Thereafter		168
Total minimum lease payments	$	367

Payments for other commitments related to operating leases amounted to $43million in 2016, $41 million in 2015, and $42 million in 2014.  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, 2016

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)		2016		2015		2014
Administrative service revenue	$	70	$	51	$	51
Operating expenses		(73)		(53)		(53)
Interest income		1		1		1
Interest expense		(10)		(10)		(14)
Other income (expense)		2		30		(1)
Equity in earnings of subsidiaries		1,388		852		1,413
Income before income taxes		1,378		871		1,397
Income tax benefit		15		3		39
Net income	$	1,393	$	874	$	1,436
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $1,
$0, and $10, at respective dates)	$	(2)	$	(1)	$	(14)
Net change in investments (net of taxes of $0, $12, and $17, at respective dates)		-		(17)		(25)
Total other comprehensive income (loss)		(2)		(18)		(39)
Comprehensive Income	$	1,391	$	856	$	1,397
Weighted Average Common Shares Outstanding, Basic		499		484		468
Weighted Average Common Shares Outstanding, Diluted		501		487		470
Net earnings per common share, basic	$	2.79	$	1.81	$	3.07
Net earnings per common share, diluted	$	2.78	$	1.79	$	3.06

PG&E CORPORATION

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

CONDENSED BALANCE SHEETS

	Balance at December31,
(in millions)	2016		2015
ASSETS
Current Assets
Cash and cash equivalents	$	106		$	64
Advances to affiliates		24			22
Income taxes receivable		25			24
Other		-			1
Total current assets		155			111
Noncurrent Assets
Equipment		2			2
Accumulated depreciation		(2)			(2)
Net equipment		-			-
Investments in subsidiaries		18,172			16,837
Other investments		133			130
Deferred income taxes		267			250
Total noncurrent assets		18,572			17,217
Total Assets	$	18,727		$	17,328
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable – other		7			3
Other		274			246
Total current liabilities		281			249
Noncurrent Liabilities
Long-term debt		348			348
Other		158			155
Total noncurrent liabilities		506			503
Common Shareholders’ Equity
Common stock		12,198			11,282
Reinvested earnings		5,751			5,301
Accumulated other comprehensive income (loss)		(9)			(7)
Total common shareholders’ equity		17,940			16,576
Total Liabilities and Shareholders’ Equity	$	18,727		$	17,328

PG&E CORPORATION

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

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2016		2015		2014
Cash Flows from Operating Activities:
Net income	$	1,393	$	874	$	1,436
Adjustments to reconcile net income to net cash provided by
operating activities:
Stock-based compensation amortization		74		66		65
Equity in earnings of subsidiaries		(1,388)		(852)		(1,413)
Deferred income taxes and tax credits-net		11		10		(72)
Noncurrent income taxes receivable/payable		-		-		5
Current income taxes receivable/payable		(1)		5		(16)
Other		(24)		(70)		43
Net cash provided by operating activities		65		33		48
Cash Flows From Investing Activities:
Investment in subsidiaries		(835)		(705)		(978)
Dividends received from subsidiaries (1)		911		716		716
Proceeds from tax equity investments		-		-		368
Net cash provided by (used in) investing activities		76		11		106
Cash Flows From Financing Activities:
Borrowings (repayments) under revolving credit facilities		-		-		(260)
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $3		-		-		347
Repayments of long-term debt		-		-		(350)
Common stock issued		822		780		802
Common stock dividends paid(2)		(921)		(856)		(828)
Net cash provided by (used in) financing activities		(99)		(76)		(289)
Net change in cash and cash equivalents		42		(32)		(135)
Cash and cash equivalents at January 1		64		96		231
Cash and cash equivalents at December 31	$	106	$	64	$	96
Supplemental disclosure of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(9)	$	(9)	$	(15)
Income taxes, net		(13)		-		1
Supplemental disclosure of noncash investing and financing activities
Noncash common stock issuances	$	20	$	21	$	21
Common stock dividends declared but not yet paid		248		224		217

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

(2)In January of 2016, PG&E Corporation paid a quarterly common stock dividend of $0.455 per share.
In April, July and October of 2016, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share.
In January, April, July, and October of 2015 and 2014, 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, 2016

Schedule II - Consolidated Valuation And Qualifying Accounts

PG&E Corporation

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2016, 2015, and 2014

(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:
2016:
Allowance for uncollectible accounts (1)	$	54	$	50	$	-	$	46	$	58
2015:
Allowance for uncollectible accounts (1)	$	66	$	43	$	-	$	55	$	54
2014:
Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66

(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, 2016, 2015, and 2014

(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:
2016:
Allowance for uncollectible accounts (1)	$	54	$	50	$	-	$	46	$	58
2015:
Allowance for uncollectible accounts (1)	$	66	$	43	$	-	$	55	$	54
2014:
Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66

(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, 2016

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 or four 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

Prior to October 2016, restricted cash primarily consisted 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)	2016		2015
Electricity generating facilities (1)	5 to 100	$	11,308	$	9,860
Electricity distribution facilities	15 to 55		29,836		28,476
Electricity transmission facilities	15 to 75		11,412		10,196
Natural gas distribution facilities	5 to 60		11,362		10,397
Natural gas transmission and storage facilities	5 to 65		6,491		6,352
Construction work in progress			2,184		2,059
Total property, plant, and equipment			72,593		67,340
Accumulated depreciation			(22,012)		(20,617)
Net property, plant, and equipment		$	50,581	$	46,723

(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 3.73% in 2016, 3.80% in 2015, and 3.77% in 2014.  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 $51 million and $112 million during 2016, $48 million and $107 million during 2015, and $45 million and $100 million during 2014.

Asset Retirement Obligations

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2016 and 2015, including nuclear decommissioning obligations:

(in millions)		2016		2015
ARO liability at beginning of year	$	3,643	$	3,575
Revision in estimated cash flows		968		13
Accretion		194		169
Liabilities settled		(121)		(114)
ARO liability at end of year	$	4,684	$	3,643

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.  InMarch2016, the Utility submitted its updated decommissioningcost estimate to the CPUC.  As a result, the estimated undiscounted cost to decommission the Utility’s nuclear power plants increased by approximately $1.4billion. The change in total estimated cost resulted in an $818 million adjustment to theARO. The adjustment was a result of increased estimatedcosts related to spentfuel storage, staffing, and out-of-state waste disposal. 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 recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue untilthose costs are fully recovered. The Utility requested that the CPUC authorize the collection ofincreased annual revenue requirementsbeginning on January 1, 2017 based ontheseupdated cost estimates.

On August 11, 2016, the Utility submitted an application to the CPUC to retire Diablo Canyon at the expiration of its current operating licenses in 2024 (Unit 1) and 2025 (Unit 2). The application includes a joint proposal between the Utility and certain interested parties, entered into on June 20, 2016, which resulted in a $115 million increase to the ARO recognized on the Consolidated Balance Sheets in June 2016.

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 $3.5 billion and $2.5 billion at December 31, 2016 and 2015, respectively.  The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $5.1 billion and $3.5 billion at December 31, 2016 and 2015 (or $7.3 billion in future dollars), respectively. These estimates are based on the 2016 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.  (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, 2016, 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, 2016, it did not consolidate any of them.

Recently Adopted Accounting Guidance

Recently Adopted Accounting Guidance

Share-Based Payment Accounting

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718), which amends the existing guidance relating to the accounting for share-based payment awards issued to employees, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.  PG&E Corporation and the Utility have adopted this standard as of the fourth quarter of 2016. 

ASU 2016-09 requires recognition of excess tax benefits and deficiencies in the income statement, which resulted in the recognition of $6.3 millionin income tax benefit for PG&E Corporation and the Utility for the year ended December 31, 2016.  Previously, these amounts were recognized in additional paid-in capital.  Previously unrecognized excess tax benefits were reclassified via a cumulative-effect adjustment.  ASU 2016-09 also requires excess tax benefits and deficiencies to be prospectively excluded from assumed future proceeds in the calculation of diluted shares when calculating diluted earnings per share utilizing the treasury stock method.  The effect of this change on diluted EPS is immaterial.  Additionally, excess income tax benefits from stock-based compensation arrangements are now classified as cash flows from operating activities rather than as cash flows from financing activities, which resulted in an increase to cash flows from operating activities of approximately $7.2 millionfor the year ended December 31, 2016. 

Furthermore, ASU 2016-09 requires, on a retrospective basis, that employee taxes paid for withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities.  As such, the consolidated statements of cash flows for PG&E Corporation and the Utility for the prior periods presented were restated.  This change resulted in an increase to cash flows from operating activities and a decrease to cash flows from financing activities of $34.6 million, $26.8 million, and $13.2 millionfor the years ended December 31, 2016, 2015, and 2014, respectively.

PG&E Corporation and the Utility have elected to continue to estimate forfeitures expected to occur to determine the amount of compensation cost to be recognized in each period and have not changed their policy on statutory withholding requirements and will continue to allow the employee to withhold up to the minimum statutory withholding requirements.

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 standardizes reporting practices related to the fair value hierarchy for all investments for which fair value is measured using net asset value per share.  PG&E Corporation and the Utility adopted this guidance effective January 1, 2016.  The adoption of this standard did not have a material impact on their Consolidated Financial Statements.  All prior periods presented in these Consolidated Financial Statements reflect the retrospective adoption of this guidance.  (See Notes 10 and 11 below.)

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.  PG&E Corporation and the Utility adopted this guidance effective January 1, 2016.  The adoption of this guidance did not have a material impact on their Consolidated Financial Statements.

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 the existing guidance relating to the presentation of debt issuance costs.  The amendments in this ASU 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 adopted this guidance effective January 1, 2016 and applied the requirements retrospectively for all periods presented.  The adoption of this guidance did not have a material impact on their Consolidated Financial Statements.  PG&E Corporation and the Utility restated $105 million and $103 million, respectively, of debt issuance costs as of December 31, 2015 with no impact to net income or total shareholders’ equity previously reported.  All prior periods presented in these Consolidated Financial Statements reflect the retrospective adoption of this guidance.

Accounting Standards Issued But Not Yet Adopted

Restricted Cash

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230), which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows.  The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted.  PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Statements of Cash Flows.

Recognition of Lease Assets and Liabilities

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing guidance relating to the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements.  Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheet, which were previously not recognized.  The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019 with retrospective application.  PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 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 the existing guidance relating to 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.

Revenue Recognition Standard

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance, effective January 1, 2018.  The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdiction, and capital markets and to provide more useful information to users of financial statements through improved disclosure requirements.  PG&E Corporation and the Utility do not plan to early adopt the standard and are currently reviewing all revenue streams and evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.  The Utility does not expect ASU 2014-09 to materially impact the timing or recognition of revenue generated through the sale and delivery of electricity and natural gas to customers.  However, the Utility continues to consider the impacts of outstanding industry-related issues being addressed by the American Institute of CPAs’ Revenue Recognition Working Group and the FASB’s Transition Resource Group.

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Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

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)	2016		2015
Electricity generating facilities (1)	5 to 100	$	11,308	$	9,860
Electricity distribution facilities	15 to 55		29,836		28,476
Electricity transmission facilities	15 to 75		11,412		10,196
Natural gas distribution facilities	5 to 60		11,362		10,397
Natural gas transmission and storage facilities	5 to 65		6,491		6,352
Construction work in progress			2,184		2,059
Total property, plant, and equipment			72,593		67,340
Accumulated depreciation			(22,012)		(20,617)
Net property, plant, and equipment		$	50,581	$	46,723

(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)		2016		2015
ARO liability at beginning of year	$	3,643	$	3,575
Revision in estimated cash flows		968		13
Accretion		194		169
Liabilities settled		(121)		(114)
ARO liability at end of year	$	4,684	$	3,643

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, 2016 consisted of the following:

	Pension		Other
(in millions, net of income tax)	Benefits		Benefits		Total
Beginning balance	$	(23)	$	16	$	(7)
Other comprehensive income before reclassifications:
Unrecognized prior service cost
(net of taxes of $37 and $15, respectively)		54		(21)		33
Unrecognized net actuarial loss
(net of taxes of $45 and $15, respectively)		(64)		21		(43)
Regulatory account transfer
(net of taxes of $5 and $0, respectively)		7		-		7
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $3 and $6, respectively) (1)		5		9		14
Amortization of net actuarial loss
(net of taxes of $10 and $2, respectively) (1)		14		2		16
Regulatory account transfer
(net of taxes of $13 and $8, respectively) (1)		(18)		(11)		(29)
Net current period other comprehensive loss		(2)		-		(2)
Ending balance	$	(25)	$	16	$	(9)

(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, 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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Regulatory Assets, Liabilities, And Balancing Accounts (Tables)

12 Months Ended

Dec. 31, 2016

Regulatory Assets, Liabilities, And Balancing Accounts [Abstract]

Long-Term Regulatory Assets

	Balance at December 31,					Recovery
(in millions)	2016		2015			Period
Pension benefits (1)	$	2,429	$	2,414	Indefinitely(3)
Deferred income taxes(1)		3,859		3,054	47 years
Utility retained generation(2)		364		411	9 years
Environmental compliance costs (1)		778		748	32 years
Price risk management (1)		92		138	10 years
Unamortized loss, net of gain, on reacquired debt (1)		76		94	26 years
Other		353		170	Various
Total long-term regulatory assets	$	7,951	$	7,029

(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) 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)	2016		2015
Cost of removal obligations (1)	$	5,060	$	4,605
Recoveries in excess of AROs (2)		626		631
Public purpose programs(3)		567		600
Other		552		485
Total long-term regulatory liabilities	$	6,805	$	6,321

(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)	2016		2015
Electric distribution	$	132	$	380
Utility generation		48		122
Gas distribution and transmission		541		493
Energy procurement		132		262
Public purpose programs		106		155
Other		541		348
Total regulatory balancing accounts receivable	$	1,500	$	1,760

Current Regulatory Balancing Accounts Payable

	Payable
	Balance at December 31,
(in millions)	2016		2015
Gas distribution and transmission	$	48	$	-
Energy procurement		13		112
Public purpose programs		264		244
Other		320		359
Total regulatory balancing accounts payable	$	645	$	715

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Debt (Tables)

12 Months Ended

Dec. 31, 2016

Debt [Abstract]

Schedule Of Long-Term Debt

		December 31,
(in millions)		2016		2015
PG&E Corporation
Senior notes:
Maturity	Interest Rates
2019	2.40%		350		350
Unamortized discount, net of premium and debt issuance costs			(2)		(2)
Total PG&E Corporation long-term debt			348		348
Utility
Senior notes:
Maturity	Interest Rates
2017	5.625%		700		700
2018	8.25%		800		800
2020	3.50%		800		800
2021	3.25% to 4.25%		550		550
2022 through 2046	2.45% to 6.35%		12,775		11,775
Less: current portion			(700)		-
Unamortized discount, net of premium and debt issuance costs			(161)		(156)
Total senior notes, net of current portion			14,764		14,469
Pollution control bonds:
Maturity	Interest Rates
Series 2004 A-D, due 2023(1)	4.75%		345		345
Series 2009 A-D, due 2026 (2)	variable rate(4)		149		309
Series 1996 C, E, F, 1997 B due 2026(3)	variable rate(5)		614		614
Less: current portion			-		(160)
Total pollution control bonds			1,108		1,108
Total Utility long-term debt, net of current portion			15,872		15,577
Total consolidated long-term debt, net of current portion		$	16,220	$	15,925

(1) The Utility has obtained credit support from an insurance company for these bonds.

(2) Each series of these bonds is supported by a separate direct-pay letter of credit.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent. Series C and D pollution control bonds were redeemed on November 30, 2016.

(3) 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.

(4) At December 31, 2016, the interest rate on these bonds was 0.74%.

(5) At December 31, 2016, the interest rate on these bonds ranged from 0.72% - 0.73%.

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 2021	$	300	(1)		$	-		$	-		$	300
Utility	April 2021		3,000	(2)			41			1,016			1,943
Total revolving credit facilities		$	3,300			$	41		$	1,016		$	2,243

(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)	2017		2018		2019		2020		2021		Thereafter		Total
PG&E Corporation
Average fixed interest rate		-		-		2.40%		-		-		-		2.40%
Fixed rate obligations	$	-	$	-	$	350	$	-	$	-	$	-	$	350
Utility
Average fixed interest rate		5.625%		8.25%		-		3.50%		3.80%		4.84%		4.94%
Fixed rate obligations	$	700	$	800	$	-	$	800	$	550	$	13,120	$	15,970
Variable interest rate
as of December 31, 2016		-		-		0.74%		0.73%		-		-		0.73%
Variable rate obligations (1)	$	-	$	-	$	149	$	614	$	-	$	-	$	763
Total consolidated debt	$	700	$	800	$	499	$	1,414	$	550	$	13,120	$	17,083

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

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Common Stock And Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2016

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule Of Compensation Expense For Share-Based Incentive Awards

(in millions)	2016		2015		2014
Restricted stock units	$	53	$	47	$	42
Performance shares		55		46		36
Total compensation expense (pre-tax)	$	108	$	93	$	78
Total compensation expense (after-tax)	$	64	$	55	$	47

Schedule Of Restricted Stock Units

The following table summarizes restricted stock unit activity for 2016:

	Number of	Weighted Average Grant-
	Restricted Stock Units	Date Fair Value
Nonvested at January 1	1,972,899	$	47.33
Granted	776,312	$	56.68
Vested	(770,968)	$	46.79
Forfeited	(55,233)	$	49.65
Nonvested at December 31	1,923,010	$	51.26

Schedule Of Performance Shares

The following table summarizes activity for performance shares in 2016:

	Number of	Weighted Average Grant-
	Performance Shares	Date Fair Value
Nonvested at January 1	1,450,612	$	59.24
Granted	1,233,884		53.61
Vested	(777,719)		51.81
Forfeited (1)	(67,922)		58.20
Nonvested at December 31	1,838,855	$	58.65
(1)Includes performance shares that expired with zero value as performance targets were not met.

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2016

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)	2016		2015		2014
Income available for common shareholders	$	1,393	$	874	$	1,436
Weighted average common shares outstanding, basic		499		484		468
Add incremental shares from assumed conversions:
Employee share-based compensation		2		3		2
Weighted average common share outstanding, diluted		501		487		470
Total earnings per common share, diluted	$	2.78	$	1.79	$	3.06

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Taxes [Abstract]

Schedule Of Components Of Income Tax Expense (Benefit)

	PG&E Corporation									Utility
	Year Ended December 31,
(in millions)	2016		2015			2014			2016				2015			2014
Current:
Federal	$	(105)		$	(89)		$	(84)			$	(105)		$	(88)		$	(84)
State		(70)			11			(41)				(66)			6			(29)
Deferred:
Federal		218			131			396				229			136			426
State		16			(76)			78				16			(69)			75
Tax credits		(4)			(4)			(4)				(4)			(4)			(4)
Income tax provision (benefit)	$	55		$	(27)		$	345			$	70		$	(19)		$	384

Schedule Of Deferred Tax Assets And Liabilities

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2016		2015			2016		2015
Deferred income tax assets:
Tax carryforwards		1,851		1,703			1,596		1,462
Other(1)		463		757			402		700
Total deferred income tax assets	$	2,314	$	2,460		$	1,998	$	2,162
Deferred income tax liabilities:
Property related basis differences		10,429		9,656			10,411		9,638
Income tax regulatory asset (2)		1,572		1,244			1,572		1,245
Other(3)		526		766			525		766
Total deferred income tax liabilities	$	12,527	$	11,666		$	12,508	$	11,649
Total net deferred income tax liabilities	$	10,213	$	9,206		$	10,510	$	9,487

(1)Amounts include compensation and benefits, environmental reserve, and customer advances for construction. 

(2)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 of the Notes to the Consolidated Financial Statements in Item 8.)

(3)Amounts primarily relate to regulatory balancing accounts.  Greenhouse gas allowances are temporary timing differences that reverse through regulatory balancing accounts. 

Schedule Of Effective Income Tax Rate Reconciliation

	PG&E Corporation										Utility
	Year Ended December 31,
	2016			2015			2014			2016				2015			2014
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)	(2.5)		(4.9)			1.4			(2.2)				(4.8)			1.6
Effect of regulatory treatment
of fixed asset differences (2)	(23.7)		(33.6)			(15.0)			(23.4)				(33.7)			(14.7)
Tax credits	(0.8)		(1.3)			(0.7)			(0.8)				(1.3)			(0.7)
Benefit of loss carryback	(1.1)		(1.5)			(0.8)			(1.1)				(1.5)			(0.8)
Non deductible penalties (3)	0.8		4.3			0.3			0.8				4.3			0.3
Other, net(4)	(3.9)		(1.1)			(0.8)			(3.5)				(0.2)			0.4
Effective tax rate	3.8	%	(3.1)		%	19.4		%	4.8			%	(2.2)		%	21.1		%

(1)Includes the effect of state flow-through ratemaking treatment.  In 2016 and 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 as authorized by the 2014 GRC decision in all periods presented and by the 2015 GT&S decision which impacts only 2016.  All amounts are impacted by the level of income before income taxes.  The 2014 GRC and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. 

(3) Primarily represents the effects of non-tax deductible fines and penalties associated with the natural gas distribution facilities record-keeping decision for the year ended December 31, 2016 and the effects of the Penalty Decision for the year ended December 31, 2015.  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.

(4) In 2016, the amount primarily represents the impact of tax audit settlements.

Schedule Of Change In Unrecognized Tax Benefits

	PG&E Corporation						Utility
(in millions)	2016		2015		2014		2016		2015		2014
Balance at beginning of year	$	468	$	713	$	666	$	462	$	707	$	660
Additions for tax position taken
during a prior year		-		40		7		-		40		7
Reductions for tax position
taken during a prior year		(77)		(349)		(9)		(77)		(349)		(9)
Additions for tax position
taken during the current year		56		64		61		56		64		61
Settlements		(59)		-		(12)		(59)		-		(12)
Balance at end of year	$	388	$	468	$	713	$	382	$	462	$	707

Schedule of Operating Loss And Tax Credit Carryforward Balances

	December 31,		Expiration
(in millions)	2016		Year
Federal:
Net operating loss carryforward	$	5,009	2029 - 2036
Tax credit carryforward		116	2029 - 2036
Charitable contribution loss carryforward		192	2017 - 2021
State:
Net operating loss carryforward	$	-	N/A
Tax credit carryforward		51	Various
Charitable contribution loss carryforward		112	2019 - 2021

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Derivatives And Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2016

Derivatives And Hedging Activities [Abstract]

Volumes Of Outstanding Derivative Contracts

		Contract Volume
Underlying Product	Instruments	2016	2015
Natural Gas (1)(MMBtus (2))	Forwards and Swaps	323,301,331	333,091,813
	Options	96,602,785	111,550,004
Electricity (Megawatt-hours)	Forwards and Swaps	3,287,397	3,663,512
	Congestion Revenue Rights (3)	278,143,281	216,383,389

(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, 2016, 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	$	91	$	(10)	$	1	$	82
Other noncurrent assets – other		149		(9)		-		140
Current liabilities – other		(48)		10		-		(38)
Noncurrent liabilities – other		(101)		9		3		(89)
Total commodity risk	$	91	$	-	$	4	$	95

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

Gains And Losses On Derivative Instruments

	Commodity Risk
	For the year ended December 31,
(in millions)	2016		2015		2014
Unrealized gain/(loss) - regulatory assets and liabilities (1)	$	64	$	(6)	$	124
Realized loss - cost of electricity (2)		(53)		(14)		(83)
Realized loss - cost of natural gas (2)		(18)		(10)		(8)
Total commodity risk	$	(7)	$	(30)	$	33

(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)	2016		2015
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(24)	$	(2)
Related derivatives in an asset position		19		-
Collateral posting in the normal course of business related to
these derivatives		4		-
Net position of derivative contracts/additional collateral
posting requirements(1)	$	(1)	$	(2)

(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, 2016

Fair Value Measurements [Abstract]

Assets And Liabilities Measured At Fair Value On A Recurring Basis

	Fair Value Measurements
	At December 31, 2016
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	105	$	-	$	-	$	-	$	105
Nuclear decommissioning trusts
Short-term investments		9		-		-		-		9
Global equity securities		1,724		-		-		-		1,724
Fixed-income securities		665		527		-		-		1,192
Assets measured at NAV		-		-		-		-		14
Total nuclear decommissioning trusts (2)		2,398		527		-		-		2,939
Price risk management instruments
(Note 9)
Electricity		30		18		181		(18)		211
Gas		-		11		-		-		11
Total price risk management		30		29		181		(18)		222
instruments
Rabbi trusts
Fixed-income securities		-		61		-		-		61
Life insurance contracts		-		70		-		-		70
Total rabbi trusts		-		131		-		-		131
Long-term disability trust
Short-term investments		8		-		-		-		8
Assets measured at NAV		-		-		-		-		170
Total long-term disability trust		8		-		-		-		178
TOTAL ASSETS	$	2,541	$	687	$	181	$	(18)	$	3,575
Liabilities:
Price risk management instruments
(Note 9)
Electricity	$	9	$	12	$	126	$	(21)	$	126
Gas		-		2		-		(1)		1
TOTAL LIABILITIES	$	9	$	14	$	126	$	(22)	$	127

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

(2) Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	64	$	-	$	-	$	-	$	64
Nuclear decommissioning trusts
Short-term investments		36		-		-		-		36
Global equity securities		1,520		-		-		-		1,520
Fixed-income securities		694		521		-		-		1,215
Assets measured at NAV		-		-		-		-		13
Total nuclear decommissioning trusts (2)		2,250		521		-		-		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
Short-term investments		7		-		-		-		7
Assets measured at NAV		-		-		-		-		158
Total long-term disability trust		7		-		-		-		165
TOTAL ASSETS	$	2,321	$	658	$	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.

Sensitivity Analysis

	Fair Value at
(in millions)	At December 31, 2016					Valuation		Unobservable
Fair Value Measurement	Assets		Liabilities		Technique		Input		Range (1)
Congestion revenue rights	$	181	$	35	Market approach		CRR auction prices		$	(11.88) - 6.93
Power purchase agreements	$	-	$	91	Discounted cash flow		Forward prices		$	18.07 - 38.80

1. Represents price per megawatt-hour

	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

Level 3 Reconciliation

	Price Risk Management Instruments
(in millions)	2016			2015
Asset (liability) balance as of January 1	$	89	$		69
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(34)			20
Asset (liability) balance as of December 31	$	55	$		89

(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,
	2016					2015
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount			Level 2 Fair Value
Debt (Note 4)
PG&E Corporation	$	348	$	352	$		348	$	354
Utility		15,813		17,790			14,818		16,422

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, 2016
Nuclear decommissioning trusts
Short-term investments	$	9	$	-	$	-	$	9
Global equity securities		584		1,157		(3)		1,738
Fixed-income securities		1,156		48		(12)		1,192
Total (1)	$	1,749	$	1,205	$	(15)	$	2,939
As of December 31, 2015
Nuclear decommissioning trusts
Short-term 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

(1) Represents amounts before deducting $333 million and $314 million at December 31, 2016 and 2015, respectively, primarily related to deferred taxes on appreciation of investment value.

Schedule Of Long Term Debt Repayments

	As of
(in millions)	December 31, 2016
Less than 1 year	$	13
1–5 years		419
5–10 years		255
More than 10 years		505
Total maturities of fixed-income securities	$	1,192

Schedule Of Activity For Debt And Equity Securities

	2016		2015		2014
(in millions)
Proceeds from sales and maturities of nuclear decommissioning
investments	$	1,295	$	1,268	$	1,336
Gross realized gains on securities held as available-for-sale		18		55		118
Gross realized losses on securities held as available-for-sale		(26)		(37)		(12)

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2016

Defined Benefit Plan Disclosure [Line Items]

Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status

Pension Plan

(in millions)	2016		2015
Change in plan assets:
Fair value of plan assets at beginning of year	$	13,745		$	14,216
Actual return on plan assets		1,358			(176)
Company contributions		334			334
Benefits and expenses paid		(708)			(629)
Fair value of plan assets at end of year	$	14,729		$	13,745
Change in benefit obligation:
Benefit obligation at beginning of year	$	16,299		$	16,696
Service cost for benefits earned		453			479
Interest cost		715			673
Actuarial (gain) loss		637			(922)
Plan amendments		(91)			1
Transitional costs		-			1
Benefits and expenses paid		(708)			(629)
Benefit obligation at end of year (1)	$	17,305		$	16,299
Funded Status:
Current liability	$	(7)		$	(6)
Noncurrent liability		(2,569)			(2,547)
Net liability at end of year	$	(2,576)		$	(2,553)

(1) PG&E Corporation’s accumulated benefit obligation was $15.6 billion and $14.7 billion at December 31, 2016 and 2015, respectively.

Postretirement Benefits Other than Pensions

(in millions)	2016		2015
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,035		$	2,092
Actual return on plan assets		167			(26)
Company contributions		52			61
Plan participant contribution		85			68
Benefits and expenses paid		(166)			(160)
Fair value of plan assets at end of year	$	2,173		$	2,035
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,766		$	1,811
Service cost for benefits earned		52			55
Interest cost		76			71
Actuarial (gain) loss		11			(98)
Plan amendments		37			-
Transitional costs		-			1
Benefits and expenses paid		(153)			(146)
Federal subsidy on benefits paid		3			4
Plan participant contributions		85			68
Benefit obligation at end of year	$	1,877		$	1,766
Funded Status: (1)
Noncurrent asset	$	368		$	344
Noncurrent liability		(72)			(75)
Net asset at end of year	$	296		$	269

(1) At December 31, 2016 and 2015, 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)	2016		2015			2014
Service cost	$	453		$	479		$	383
Interest cost		715			673			695
Expected return on plan assets		(828)			(873)			(807)
Amortization of prior service cost		8			15			20
Amortization of net actuarial loss		24			10			2
Net periodic benefit cost		372			304			293
Less: transfer to regulatory account (1)		(34)			34			42
Total expense recognized	$	338		$	338		$	335

(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)	2016		2015			2014
Service cost	$	52		$	55		$	45
Interest cost		76			71			76
Expected return on plan assets		(107)			(112)			(103)
Amortization of prior service cost		15			19			23
Amortization of net actuarial loss		4			4			2
Net periodic benefit cost	$	40		$	37		$	43

Estimated Amortized Net Periodic Benefit For 2012

(in millions)	Pension Plan		PBOP Plans
Unrecognized prior service cost	$	(7)	$	15
Unrecognized net loss		22		4
Total	$	15	$	19

Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost

	Pension Plan						PBOP Plans
	December 31,						December 31,
	2016		2015		2014		2016		2015		2014
Discount rate	4.11	%	4.37	%	4.00	%	4.05 - 4.19	%	4.27 - 4.48	%	3.89 - 4.09	%
Rate of future compensation
increases	4.00	%	4.00	%	4.00	%	-		-		-
Expected return on plan
assets	5.30	%	6.10	%	6.20	%	2.80 - 6.00	%	3.20 - 6.60	%	3.30 - 6.70	%

Schedule Of Assumed Health Care Cost Trend

The assumed health care cost trend rate as of December 31, 2016 was 7.2%, decreasing gradually to an ultimate trend rate in 2025 and beyond of approximately 4.5%.  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	$	118	$	(120)
Effect on service and interest cost		9		(10)

Target Asset Allocation Percentages

	Pension Plan								PBOP Plans
	2017		2016			2015			2017			2016			2015
Global equity	27	%		25	%		25	%		32	%		32	%		31	%
Absolute return	5	%		5	%		5	%		3	%		3	%		3	%
Real assets	10	%		10	%		10	%		7	%		7	%		8	%
Fixed income	58	%		60	%		60	%		58	%		58	%		58	%
Total	100	%		100	%		100	%		100	%		100	%		100	%

Schedule Of Changes In Fair Value Of Plan Assets

	Fair Value Measurements
	At December 31,
	2016												2015
(in millions)	Level 1			Level 2			Level 3			Total				Level 1			Level 2			Level 3			Total
Pension Plan:
Short-term investments	$	364	$		369	$		-	$		733	$			247	$		375	$		-	$		622
Global equity		996			-			-			996				903			-			-			903
Real assets		610			-			-			610				581			-			-			581
Fixed-income		1,754			4,774			5			6,533				1,841			4,495			3			6,339
Assets measured at NAV		-			-			-			5,950				-			-			-			5,308
Total	$	3,724	$		5,143	$		5	$		14,822	$			3,572	$		4,870	$		3	$		13,753
PBOP Plans:
Short-term investments	$	33	$		-	$		-	$		33	$			20	$		-	$		-	$		20
Global equity		115			-			-			115				104			-			-			104
Real assets		70			-			-			70				69			-			-			69
Fixed-income		150			656			-			806				150			632			-			782
Assets measured at NAV		-			-			-			1,153				-			-			-			1,065
Total	$	368	$		656	$		-	$		2,177	$			343	$		632	$		-	$		2,040
Total plan assets at fair value									$		16,999											$		15,793

Schedule Of Level 3 Reconciliation

The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2016 and 2015:

(in millions)	Fixed-
For the year ended December 31, 2016	Income
Balance at beginning of year	$	3
Actual return on plan assets:
Relating to assets still held at the reporting date		3
Relating to assets sold during the period		-
Purchases, issuances, sales, and settlements:
Purchases		-
Settlements		(1)
Balance at end of year	$	5
(in millions)	Fixed-
For the year ended December 31, 2015	Income
Balance at beginning of year	$	12
Actual return on plan assets:
Relating to assets still held at the reporting date		(3)
Relating to assets sold during the period		1
Purchases, issuances, sales, and settlements:
Purchases		2
Settlements		(9)
Balance at end of year	$	3

Schedule Of Estimated Benefits Expected To Be Paid

	Pension		PBOP		Federal
(in millions)	Plan		Plans		Subsidy
2017	$	739	$	87	$	(8)
2018		781		93		(9)
2019		821		97		(10)
2020		857		103		(10)
2021		892		108		(11)
Thereafter in the succeeding five years		4,879		592		(15)

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Related Party Agreements And Transactions (Tables)

12 Months Ended

Dec. 31, 2016

Related Party Agreements And Transactions [Abstract]

Schedule Of Significant Related Party Transactions

	Year Ended December 31,
(in millions)	2016		2015		2014
Utility revenues from:
Administrative services provided to PG&E Corporation	$	7	$	6	$	5
Utility expenses from:
Administrative services received from PG&E Corporation	$	74	$	53	$	54
Utility employee benefit due to PG&E Corporation		91		82		70

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Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Commitments And Contingencies [Abstract]

Impact Of The Penalty Decision

	Twelve Months		Cumulative		Future
	Ended		Charges		Charges
		December 31,		December 31,	and		Total
(in millions)	2016		2016		Costs		Amount
Fine paid to the state	$	-	$	300	$	-	$	300
Customer bill credit paid		-		400		-		400
Charge for disallowed capital (1)		283		689		-		689
Disallowed revenue for pipeline safety
expenses (2)		129		129		32		161
CPUC estimated cost of other remedies (3)		-		-		-		50
Total Penalty Decision fines and remedies	$	412	$	1,518	$	32	$	1,600

(1) The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs.  On December 1, 2016, the CPUC approved a final phase two decision in the Utility’s 2015 GT&S rate case which allocates $689 million of the $850 million penalty to capital expenditures.

(2) GT&S revenues have been reduced for these unrecovered expenses. The remaining charges will be recognized in the first quarter of 2017.

(3)In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision.  This table does not reflect the Utility’s remedy-related costs already incurred or the Utility’s estimated future remedy-related costs.

Schedule of Environmental Remediation Liability

	Balance at
	December 31		December 31,
(in millions)	2016		2015
Topock natural gas compressor station (1)	$	299	$	300
Hinkley natural gas compressor station (1)		135		140
Former manufactured gas plant sites owned by the Utility or third parties		285		271
Utility-owned generation facilities (other than fossil fuel-fired),   other facilities, and third-party disposal sites		131		164
Fossil fuel-fired generation facilities and sites		108		94
Total environmental remediation liability	$	958	$	969

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

Schedule Of Undiscounted Future Expected Power Purchase Agreement Payments

	Power Purchase Agreements
	Renewable		Conventional				Natural		Nuclear
(in millions)	Energy		Energy		Other		Gas		Fuel		Total
2017	$	2,233	$	815	$	369	$	536	$	97	$	4,050
2018		2,108		716		284		169		93		3,370
2019		2,144		698		225		160		95		3,322
2020		2,139		677		179		148		130		3,273
2021		2,117		585		147		93		49		2,991
Thereafter		27,685		1,168		653		455		136		30,097
Total purchase
commitments	$	38,426	$	4,659	$	1,857	$	1,561	$	600	$	47,103

Schedule of Future Minimum Payments For Operating Leases

(in millions)	Operating Leases
2017	$	44
2018		41
2019		39
2020		39
2021		36
Thereafter		168
Total minimum lease payments	$	367

Schedule Of Loss Accrual

Loss Accrual  (in millions)
Balance at December 31, 2015	$	-
Accrued losses		750
Payments		(60)
Balance at December 31, 2016	$	690

Schedule Of Insurance Receivable

Insurance Receivable (in millions)
Balance at December 31, 2015	$	-
Accrued insurance recoveries		625
Reimbursements		(50)
Balance at December 31, 2016	$	575

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Schedule I - Condensed Financial Information Of Parent (Tables)

12 Months Ended

Dec. 31, 2016

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)		2016		2015		2014
Administrative service revenue	$	70	$	51	$	51
Operating expenses		(73)		(53)		(53)
Interest income		1		1		1
Interest expense		(10)		(10)		(14)
Other income (expense)		2		30		(1)
Equity in earnings of subsidiaries		1,388		852		1,413
Income before income taxes		1,378		871		1,397
Income tax benefit		15		3		39
Net income	$	1,393	$	874	$	1,436
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $1,
$0, and $10, at respective dates)	$	(2)	$	(1)	$	(14)
Net change in investments (net of taxes of $0, $12, and $17, at respective dates)		-		(17)		(25)
Total other comprehensive income (loss)		(2)		(18)		(39)
Comprehensive Income	$	1,391	$	856	$	1,397
Weighted Average Common Shares Outstanding, Basic		499		484		468
Weighted Average Common Shares Outstanding, Diluted		501		487		470
Net earnings per common share, basic	$	2.79	$	1.81	$	3.07
Net earnings per common share, diluted	$	2.78	$	1.79	$	3.06

Schedule of Condensed Balance Sheet

PG&E CORPORATION

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

CONDENSED BALANCE SHEETS

	Balance at December31,
(in millions)	2016		2015
ASSETS
Current Assets
Cash and cash equivalents	$	106		$	64
Advances to affiliates		24			22
Income taxes receivable		25			24
Other		-			1
Total current assets		155			111
Noncurrent Assets
Equipment		2			2
Accumulated depreciation		(2)			(2)
Net equipment		-			-
Investments in subsidiaries		18,172			16,837
Other investments		133			130
Deferred income taxes		267			250
Total noncurrent assets		18,572			17,217
Total Assets	$	18,727		$	17,328
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable – other		7			3
Other		274			246
Total current liabilities		281			249
Noncurrent Liabilities
Long-term debt		348			348
Other		158			155
Total noncurrent liabilities		506			503
Common Shareholders’ Equity
Common stock		12,198			11,282
Reinvested earnings		5,751			5,301
Accumulated other comprehensive income (loss)		(9)			(7)
Total common shareholders’ equity		17,940			16,576
Total Liabilities and Shareholders’ Equity	$	18,727		$	17,328

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,
	2016		2015		2014
Cash Flows from Operating Activities:
Net income	$	1,393	$	874	$	1,436
Adjustments to reconcile net income to net cash provided by
operating activities:
Stock-based compensation amortization		74		66		65
Equity in earnings of subsidiaries		(1,388)		(852)		(1,413)
Deferred income taxes and tax credits-net		11		10		(72)
Noncurrent income taxes receivable/payable		-		-		5
Current income taxes receivable/payable		(1)		5		(16)
Other		(24)		(70)		43
Net cash provided by operating activities		65		33		48
Cash Flows From Investing Activities:
Investment in subsidiaries		(835)		(705)		(978)
Dividends received from subsidiaries (1)		911		716		716
Proceeds from tax equity investments		-		-		368
Net cash provided by (used in) investing activities		76		11		106
Cash Flows From Financing Activities:
Borrowings (repayments) under revolving credit facilities		-		-		(260)
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $3		-		-		347
Repayments of long-term debt		-		-		(350)
Common stock issued		822		780		802
Common stock dividends paid(2)		(921)		(856)		(828)
Net cash provided by (used in) financing activities		(99)		(76)		(289)
Net change in cash and cash equivalents		42		(32)		(135)
Cash and cash equivalents at January 1		64		96		231
Cash and cash equivalents at December 31	$	106	$	64	$	96
Supplemental disclosure of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(9)	$	(9)	$	(15)
Income taxes, net		(13)		-		1
Supplemental disclosure of noncash investing and financing activities
Noncash common stock issuances	$	20	$	21	$	21
Common stock dividends declared but not yet paid		248		224		217

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

(2)In January of 2016, PG&E Corporation paid a quarterly common stock dividend of $0.455 per share.
In April, July and October of 2016, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share.
In January, April, July, and October of 2015 and 2014, 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, 2016

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, 2016, 2015, and 2014

(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:
2016:
Allowance for uncollectible accounts (1)	$	54	$	50	$	-	$	46	$	58
2015:
Allowance for uncollectible accounts (1)	$	66	$	43	$	-	$	55	$	54
2014:
Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66

(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, 2016, 2015, and 2014

(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:
2016:
Allowance for uncollectible accounts (1)	$	54	$	50	$	-	$	46	$	58
2015:
Allowance for uncollectible accounts (1)	$	66	$	43	$	-	$	55	$	54
2014:
Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66

(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 Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Increase to cash flows from operating activities	$ 379,000	$ 326,000	$ 286,000
Decrease to cash flows from financing activities	(44,000)	(27,000)	29,000
Income tax provision (benefit)	$ 55,000	$ (27,000)	$ 345,000
Pacific Gas And Electric Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Composite depreciation rate	3.73%	3.80%	3.77%
AFUDC interest recorded	$ 51,000	$ 48,000	$ 45,000
AFUDC equity recorded	112,000	107,000	100,000
Nuclear decommissioning obligation accrued	3,500,000	2,500,000
Estimated cost recovery on spent nuclear fuel storage proceeding every year	4,300,000	3,500,000
Approximate estimated nuclear decommissioning cost in future dollars	7,300,000	6,100,000
Increase to cash flows from operating activities	306,000	263,000	226,000
Decrease to cash flows from financing activities	(30,000)	(13,000)	43,000
Income tax provision (benefit)	70,000	(19,000)	384,000
New Accounting Pronouncement [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Increase to cash flows from operating activities	7,200
Decrease to cash flows from financing activities	34,600	$ 26,800	$ 13,200
Income tax provision (benefit)	6,300
Accounting Standards Update 2015-03 [Member] | Pacific Gas And Electric Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt issuance costs	103,000
Accounting Standards Update 2015-03 [Member] | PGE Corporation and Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt issuance costs	$ 105,000

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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, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Accumulated depreciation		$ (22,012)	$ (20,617)
Net property, plant, and equipment		50,581	46,723
Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment		72,593	67,340
Electricity generating facilities [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	[1]	$ 11,308	9,860
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		$ 29,836	28,476
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		$ 11,412	10,196
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		$ 11,362	10,397
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		$ 6,491	6,352
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		$ 2,184	$ 2,059

[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, 2016	Dec. 31, 2015
Summary Of Significant Accounting Policies [Abstract]
Balance at beginning of year	$ 3,643	$ 3,575
Revision in estimated cash flows	968	13
Accretion	194	169
Liabilities settled	(121)	(114)
Balance at end of year	$ 4,684	$ 3,643

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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, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance	$ (7)
Change in investments	0	$ (17)	$ (25)
Total other comprehensive income (loss)	(2)	(18)	(39)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance	(9)	(7)
Net actuarial loss tax	1	0	10
Change in investments tax	0	12	17
Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss	(16)	(9)
Unrecognized prior service cost	14	19
Transfer to regulatory account	29	26
Realized gain on investments		(17)
Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized prior service cost	33
Transfer to regulatory account	(7)	(104)
Amortization of net actuarial loss	(43)	(107)
Other Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance	16
Unrecognized net actuarial loss	4
Unrecognized prior service cost	15
Amortization of prior service cost	15	19	23
Amortization of net actuarial loss	4	4	$ 2
Total other comprehensive income (loss)	0	1
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance	16	16
Other Benefits [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss	(2)	(3)
Unrecognized prior service cost	9	11
Transfer to regulatory account	11	13
Realized gain on investments		0
Net actuarial loss tax	2	1
Transfer To Regulatory Account Tax	8	9
Amortization of prior service cost tax	6	8
Realized gain on investments tax		0
Other Benefits [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized prior service cost	(21)
Transfer to regulatory account	0	(31)
Amortization of net actuarial loss	21	(31)
Net actuarial loss tax	15	21
Transfer To Regulatory Account Tax	0	21
Amortization of prior service cost tax	15
Other Investments [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance	0
Total other comprehensive income (loss)		(17)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance		0
Other Investments [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss		0
Unrecognized prior service cost		0
Transfer to regulatory account		0
Realized gain on investments		(17)
Net actuarial loss tax		0
Transfer To Regulatory Account Tax		0
Amortization of prior service cost tax		0
Realized gain on investments tax		12
Other Investments [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account		0
Amortization of net actuarial loss		0
Net actuarial loss tax		0
Transfer To Regulatory Account Tax		0
Pension [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance	(23)
Total other comprehensive income (loss)	(2)	(2)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance	(25)	(23)
Pension [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss	(14)	(6)
Unrecognized prior service cost	5	8
Transfer to regulatory account	18	13
Realized gain on investments		0
Net actuarial loss tax	10	4
Transfer To Regulatory Account Tax	13	10
Amortization of prior service cost tax	3	7
Realized gain on investments tax		0
Pension [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized prior service cost	54
Transfer to regulatory account	(7)	(73)
Amortization of net actuarial loss	(64)	(76)
Net actuarial loss tax	45	51
Transfer To Regulatory Account Tax	5	$ 51
Amortization of prior service cost tax	$ 37

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Regulatory Assets, Liabilities, And Balancing Accounts (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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)	9 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)	26 years
Current regulatory assets	$ 423	$ 517

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Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Total long-term regulatory assets		$ 7,951	$ 7,029
Deferred income taxes regulatory asset recovery maximum (years)		47 years
Weighted average remaining life of Utility retained generation assets (years)		9 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)		26 years
Retained Generation Asset Costs		$ 1,200
Pension benefits regulatory assets recovery (years)		Indefinitely
Other regulatory assets recovery (years)		Various
Current regulatory assets		$ 423	517
Pension Plans Defined Benefit [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[1],[2]	2,429	2,414
Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[2]	3,859	3,054
Utility Retained Generation [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[3]	364	411
Environmental Compliance Costs [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[2]	778	748
Price Risk Management [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[2]	92	138
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[2]	76	94
Other Regulatory Assets ( Liabilities) [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets		$ 353	$ 170

[1] 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.

[2] 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.)

[3] 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.

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Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities		$ 6,805	$ 6,321
Cost Of Removal Obligation [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	[1]	5,060	4,605
Recoveries In Excess Of ARO [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	[2]	626	631
Public Purpose Programs [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	[3]	567	600
Other Regulatory Assets ( Liabilities) [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities		$ 552	$ 485

[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, 2016	Dec. 31, 2015
Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	$ 1,500	$ 1,760
Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	645	715
Electric Distribution [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	132	380
Utility Generation [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	48	122
Public Purpose Programs [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	106	155
Public Purpose Programs [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	264	244
Gas Distribution and Transmission [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	541	493
Gas Distribution and Transmission [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	48	0
Energy Procurement [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	132	262
Energy Procurement [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	13	112
Other [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	541	348
Other [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	$ 320	$ 359

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Debt (Narrative) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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		$ 0	$ (300)	$ 0
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	[1]	$ 3,000
Commercial paper average yield		0.70%
Line of Credit Facility, Expiration Date		Apr. 27, 2021
Short-term debt matured		$ 0	$ (300)	$ 0
PG&E Corporation [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	[2]	$ 300
Commercial paper average yield		0.65%
Line of Credit Facility, Expiration Date		Apr. 27, 2021
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		837
Maximum outstanding balance		1,400
Commercial Paper [Member] | PG&E Corporation [Member]
Debt [Line Items]
Average outstanding borrowings		84
Maximum outstanding balance		$ 176

[1] Includes a $500 million lender commitment to the letter of credit sublimits 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, 2016		Dec. 31, 2015
Debt [Line Items]
Total long-term debt, net of current portion		$ 16,220		$ 15,925
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Total long-term debt, net of current portion		15,872		15,577
Utility [Member]
Debt [Line Items]
Less: current portion		700		0
Unamortized discount, net of premium and debt issuance costs		161		156
Total senior notes, net of current portion		14,764		14,469
Less: current portion		0		160
Total pollution control bonds		1,108		1,108
PG&E Corporation [Member]
Debt [Line Items]
Unamortized discount, net of premium and debt issuance costs		2		2
Total senior notes, net of current portion		348		348
Total long-term debt, net of current portion		348		348
Senior Notes, 2.40% Due 2019 [Member] | PG&E Corporation [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, 3.25% - 4.25% Due 2021[Member] | Utility [Member]
Debt [Line Items]
Senior notes		550		550
Senior Notes, 2.45% - 6.35% Due 2022 - 2046 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		12,775		11,775
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 [Member] | Utility [Member]
Debt [Line Items]
Pollution control bonds		$ 614	[1],[2],[3]	614
Interest rate on bonds, minimum		0.72%
Interest rate on bonds, maximum		0.73%
Pollution Control Bonds, Series 2004 A-D, 4.75%, Due 2023 [Member] | Utility [Member]
Debt [Line Items]
Pollution control bonds	[4]	$ 345		345
Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member]
Debt [Line Items]
Interest rate on bonds, minimum		0.74%
Interest rate on bonds, maximum		0.74%
Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member] | Utility [Member]
Debt [Line Items]
Pollution control bonds		$ 149	[3],[5]	$ 309

[1] At December 31, 2016, the interest rate on these bonds ranged from 0.72% - 0.73%

[2] Each series of these bonds is supported by a separate direct-pay letter of credit. Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent. Series C and D pollution control bonds were redeemed on November 30, 2016.

[3] 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.

[4] The Utility has obtained credit support from an insurance company for these bonds.

[5] At December 31, 2016, interest rates on these bonds were 0.74%.

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Debt (Schedule Of Long-Term Debt Repayments) (Details) $ in Millions	Dec. 31, 2016 USD ($)
Debt [Line Items]
Total consolidated long-term debt	$ 17,083
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	4.94%
Fixed rate obligations	$ 15,970
Variable interest rate as of December 31, 2016	0.73%
Variable rate obligations	$ 763	[1]
PG&E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	2.40%
Fixed rate obligations	$ 350
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	5.625%
Fixed rate obligations	$ 700
Variable interest rate as of December 31, 2016	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, 2016	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, 2016	0.74%
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, 2016	0.73%
Variable rate obligations	$ 614	[1]
2020 [Member] | PG&E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
2021 [Member]
Debt [Line Items]
Total consolidated long-term debt	$ 550
2021 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	3.80%
Fixed rate obligations	$ 550
Variable interest rate as of December 31, 2016	0.00%
Variable rate obligations	$ 0	[1]
2021 [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	$ 13,120
Thereafter [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	4.84%
Fixed rate obligations	$ 13,120
Variable interest rate as of December 31, 2016	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] The bonds due in 2026 are backed by separate letters of credit that expire 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, 2016	Jul. 02, 2015	Apr. 27, 2015
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Expiration date for credit agreement		Apr. 27, 2021
Facility Limit	[1]	$ 3,000
Letters of Credit outstanding		41
Commercial Paper		1,016
Facility Availability		1,943
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, 2021
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		41
Commercial Paper		1,016
Facility Availability		$ 2,243

[1] Includes a $500 million lender commitment to the letter of credit sublimits 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 Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Common stock, shares outstanding	506,891,874	492,025,443
Dividend per share	$ 0.49	$ 0.445
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	$ 12,198,000	$ 11,282,000
Equity Contract [Member]
Equity distribution agreement amount	$ 275,000
Common stock shares issued	2,600,000
Fees and Commissions	$ 1,300
Common stock	$ 149,000
Underwritten Public Offering [Member]
Sale of common stock in an underwritten public offering	4,900,000
Common stock issued, amount	$ 309,000
Four Zero One K Plan D R S P P Shared Based Compensation Plans [Member]
Common stock shares issued	7,400,603
Common stock	$ 364,000
Utility [Member]
Net restricted assets for revolving credit facility ratio requirement	15,800,000
Additional Common Stock Dividends	$ 25,000

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Common Stock And Share-Based Compensation (Long-Term Incentive Plan) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	13,826,995
Total Compensation Expense (pre-tax)	$ 108	$ 93	$ 78
Total Compensation Expense (after-tax)	64	55	47
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total Compensation Expense (pre-tax)	53	47	42
Performance Shares, Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total Compensation Expense (pre-tax)	$ 55	$ 46	$ 36

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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, 2016	Dec. 31, 2015	Dec. 31, 2014
Common Stock And Share-Based Compensation [Abstract]
Total fair value	$ 36	$ 57	$ 34
Total unrecognized compensation costs	$ 37
Remaining weighted average period, Years	1 year 2 months 19 days
Nonvested at January 1, Number of Restricted Stock Units	1,972,899
Granted, Number of Restricted Stock Units	776,312
Vested, Number of Restricted Stock Units	(770,968)
Forfeited, Number of Restricted Stock Units	(55,233)
Nonvested at December 31, Number of Restricted Stock Units	1,923,010	1,972,899
Nonvested at January 1, Weighted Average Grant-Date Fair Value	$ 47.33
Granted, Weighted Average Grant Date Fair Value	56.68	$ 53.3	$ 43.76
Vested, Weighted Average Grant Date Fair Value	46.79
Forfeited, Weighted Average Grant Date Fair Value	49.65
Nonvested at December 31, Weighted Average Grant-Date Fair Value	$ 51.26	$ 47.33

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Common Stock And Share-Based Compensation (Performance Shares) (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted-average period (years)		1 year 6 months 26 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		$ 40
Nonvested at January 1, Number of Performance Shares		1,450,612
Granted, Number of Performance Shares		1,233,884
Vested, Number of Performance Shares		(777,719)
Forfeited, Number of Performance Shares	[1]	(67,922)
Nonvested at December 31, Number of Performance Shares		1,838,855	1,450,612
Nonvested at January 1, Weighted Average Exercise Price		$ 59.24
Granted, Weighted Average Exercise Price		53.61	$ 68.27	$ 51.81
Vested, Weighted Average Exercise Price		51.81
Forfeited, Weighted Average Exercise Price	[1]	58.20
Nonvested at December 31, Weighted Average Exercise Price		$ 58.65	$ 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 (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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, 2016 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Income available for common shareholders	$ 1,393	$ 874	$ 1,436
Weighted average common shares outstanding, basic	499	484	468
Add Incremental Shares From Assumed conversions:
Employee share-based compensation	2	3	2
Weighted average common shares outstanding, diluted	501	487	470
Total earnings per common share, diluted	$ 2.78	$ 1.79	$ 3.06

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Income Taxes (Schedule Of Income Tax Provision) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current, Federal	$ (105)	$ (89)	$ (84)
Current, State	(70)	11	(41)
Deferred, Federal	218	131	396
Deferred, State	16	(76)	78
Tax credits	(4)	(4)	(4)
Income Tax Provision	55	(27)	345
Pacific Gas And Electric Company [Member]
Current, Federal	(105)	(88)	(84)
Current, State	(66)	6	(29)
Deferred, Federal	229	136	426
Deferred, State	16	(69)	75
Tax credits	(4)	(4)	(4)
Income Tax Provision	70	(19)	384
PG&E Corporation [Member]
Income Tax Provision	$ 15	$ 3	$ 39

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Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Pacific Gas And Electric Company [Member]
Tax carryforwards		$ 1,596	$ 1,462
Other		402	700
Total deferred income tax assets		1,998	2,162
Property related basis differences		10,411	9,638
Income tax regulatory asset		1,572	1,245	[1]
Other		525	766
Total deferred income tax liabilities		12,508	11,649
Total net deferred income tax liabilities		10,510	9,487
PG&E Corporation [Member]
Tax carryforwards		1,851	1,703
Other		463	757
Total deferred income tax assets		2,314	2,460
Property related basis differences		10,429	9,656
Income tax regulatory asset	[1]	1,572	1,244
Other		526	766
Total deferred income tax liabilities		12,527	11,666
Total net deferred income tax liabilities		$ 10,213	$ 9,206

[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, 2016	Dec. 31, 2015	Dec. 31, 2014
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]	(2.20%)	(4.80%)	1.60%
Effect of regulatory treatment of fixed asset differences	[2]	(23.40%)	(33.70%)	(14.70%)
Tax credits		(0.80%)	(1.30%)	(0.70%)
Benefit of loss carryback		(1.10%)	(1.50%)	(0.80%)
Non deductible penalties	[3]	0.80%	4.30%	0.30%
Other, net		(3.50%)	(0.20%)	0.40%
Effective tax rate		4.80%	(2.20%)	21.10%
PG&E Corporation [Member]
Federal statutory income tax rate		35.00%	35.00%	35.00%
State income tax (net of federal benefit)	[1]	(2.50%)	(4.90%)	1.40%
Effect of regulatory treatment of fixed asset differences	[2]	(23.70%)	(33.60%)	(15.00%)
Tax credits		(0.80%)	(1.30%)	(0.70%)
Benefit of loss carryback		(1.10%)	(1.50%)	(0.80%)
Non deductible penalties	[3]	0.80%	4.30%	0.30%
Other, net		(3.90%)	(1.10%)	(0.80%)
Effective tax rate		3.80%	(3.10%)	19.40%

[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, 2016	Dec. 31, 2015	Dec. 31, 2014
Pacific Gas And Electric Company [Member]
Balance at beginning of year	$ 462	$ 707	$ 660
Additions for tax position taken during a prior year	0	40	7
Reductions for tax position taken during a prior year	(77)	(349)	(9)
Additions for tax position taken during the current year	56	64	61
Settlements	(59)	0	(12)
Balance at end of year	382	462	707
PG&E Corporation [Member]
Balance at beginning of year	468	713	666
Additions for tax position taken during a prior year	0	40	7
Reductions for tax position taken during a prior year	(77)	(349)	(9)
Additions for tax position taken during the current year	56	64	61
Settlements	(59)	0	(12)
Balance at end of year	$ 388	$ 468	$ 713

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Income Taxes (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year	$ 25
Decrease of unrecognized tax benefit	70
State [Member]
Net operating loss carryforwards	0
Tax credit carryforward, amount	51
Loss carryforwards, charitable contribution	$ 112
Charitable Contribution Carryforward Expiration Date [Minimum]	Dec. 31, 2019
Charitable Contribution Carryforward Expiration Date [Maximum]	Dec. 31, 2021
Federal [Member]
Net operating loss carryforwards	$ 5,009
Tax credit carryforward, amount	116
Loss carryforwards, charitable contribution	$ 192
Tax Credit Carryforward Expiration Date [Minimum]	Dec. 31, 2029
Tax Credit Carryforward Expiration Date [Maximum]	Dec. 31, 2036
Charitable Contribution Carryforward Expiration Date [Minimum]	Dec. 31, 2017
Charitable Contribution Carryforward Expiration Date [Maximum]	Dec. 31, 2021
Minimum [Member] | State [Member]
Tax credit carryforward expiration date
Minimum [Member] | Federal [Member]
Tax credit carryforward expiration date	Dec. 31, 2029
Maximum [Member] | State [Member]
Tax credit carryforward expiration date
Maximum [Member] | Federal [Member]
Tax credit carryforward expiration date	Dec. 31, 2036

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Derivatives And Hedging Activities (Volumes Of Outstanding Derivative Contracts) (Details)		Dec. 31, 2016 MMBTU MWh	Dec. 31, 2015 MMBTU MWh
Forwards And Swaps [Member] | Natural Gas (MMBtus)[Member]
Derivative [Line Items]
Derivative Number of Instruments Held | MMBTU	[1],[2]	323,301,331	333,091,813
Forwards And Swaps [Member] | Electricity (Megawatt-hours) [Member]
Derivative [Line Items]
Derivative Number of Instruments Held | MWh		3,287,397	3,663,512
Options [Member] | Natural Gas (MMBtus)[Member]
Derivative [Line Items]
Derivative Number of Instruments Held | MMBTU	[1],[2]	96,602,785	111,550,004
Congestion Revenue Rights [Member] | Electricity (Megawatt-hours) [Member]
Derivative [Line Items]
Derivative Number of Instruments Held | MWh	[3]	278,143,281	216,383,389

[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, 2016	Dec. 31, 2015
Other Current Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	$ 91	$ 97
Cash Collateral	1	25
Total Derivative Balances	82	118
Derivative Liability Offsetting Derivative Asset	(10)	(4)
Other Noncurrent Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	149	172
Cash Collateral	0	0
Total Derivative Balances	140	170
Derivative Liability Offsetting Derivative Asset	(9)	(2)
Other Current Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(48)	(102)
Cash Collateral	0	44
Total Derivative Balances	(38)	(54)
Derivative Asset Offsetting Derivative Liability	10	4
Other Noncurrent Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(101)	(140)
Cash Collateral	3	21
Total Derivative Balances	(89)	(117)
Derivative Asset Offsetting Derivative Liability	9	2
Gross Derivative Balance [Member]
Derivatives And Hedging Activities [Line Items]
Total Gross Derivative Balance	91	27
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	4	90
Total Derivatve Balance [Member]
Derivatives And Hedging Activities [Line Items]
Total Derivative Balances	$ 95	$ 117

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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, 2016	Dec. 31, 2015	Dec. 31, 2014
Unrealized (loss) gain - regulatory assets and liabilities	[1]	$ 64	$ (6)	$ 124
Realized loss-cost of electricity	[2]	(53)	(14)	(83)
Realized loss-cost of natural gas	[2]	(18)	(10)	(8)
Total commodity risk instruments		$ (7)	$ (30)	$ 33

[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, 2016	Dec. 31, 2015
Derivatives And Hedging Activities [Abstract]
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized		$ (24)	$ (2)
Related derivatives in an asset position		19	0
Collateral posting in the normal course of business related to these derivatives		4	0
Net position of derivative contracts/additional collateral posting requirements	[1]	$ (1)	$ (2)

[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, 2016		Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value		$ 333		$ 314
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		105		64
Total assets		2,541		2,321
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		0		0
Total assets		687		658
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		0		0
Total assets		181		259
Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		0		0
Total assets	[1]	(18)		19
Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		105		64
Total assets		3,575		3,428
Nuclear Decommissioning Trusts [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		9		36
Global equity securities		1,724		1,520
Fixed-income securities		665		694
Total assets		2,398		2,250	[2]
Assets measured at NAV		0		0
Nuclear Decommissioning Trusts [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		0		0
Global equity securities		0		0
Fixed-income securities		527		521
Total assets		527		521	[2]
Assets measured at NAV		0		0
Nuclear Decommissioning Trusts [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		0		0
Global equity securities		0		0
Fixed-income securities		0		0
Total assets		0		0
Assets measured at NAV		0		0
Nuclear Decommissioning Trusts [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		0		0
Global equity securities		0		0
Fixed-income securities		0		0
Total assets		0		0
Assets measured at NAV		0		0
Nuclear Decommissioning Trusts [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		9		36
Global equity securities		1,724		1,520
Fixed-income securities		1,192		1,215
Total assets		2,939		2,784	[2]
Assets measured at NAV		14		13
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		30		0
Electric		30		0
Gas		0		0
Electric		9		69
Gas		0		0
Total liabilities		9		69
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		29		10
Electric		18		9
Gas		11		1
Electric		12		1
Gas		2		2
Total liabilities		14		3
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		181		259
Electric		181		259
Gas		0		0
Electric		126		170
Gas		0		0
Total liabilities		126		170
Price Risk Management Instruments [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		(18)		19	[1]
Electric		(18)		18	[1]
Gas		0		1
Electric	[1]	(21)		(70)
Gas		(1)	[1]	(1)
Total liabilities	[1]	(22)		(71)
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		222		288
Electric		211		286
Gas		11		2
Electric		126		170
Gas		1		1
Total liabilities		127		171
Rabbi Trusts [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fixed-income securities		0		0
Life insurance contracts		0		0
Total assets		0		0
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		61		57
Life insurance contracts		70		70
Total assets		131		127
Rabbi Trusts [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fixed-income securities		0		0
Life insurance contracts		0		0
Total assets		0		0
Rabbi Trusts [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fixed-income securities		0		0
Life insurance contracts		0		0
Total assets		0		0
Rabbi Trusts [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fixed-income securities		61		57
Life insurance contracts		70		70
Total assets		131		127
Long-Term Disability Trust [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		8		7
Total assets		8		7
Assets measured at NAV		0		0
Long-Term Disability Trust [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		0		0
Total assets		0		0
Assets measured at NAV		0		0
Long-Term Disability Trust [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		0		0
Total assets		0		0
Assets measured at NAV		0		0
Long-Term Disability Trust [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		0		0
Total assets		0		0
Assets measured at NAV		0		0
Long-Term Disability Trust [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments		8		7
Total assets		178		165
Assets measured at NAV		$ 170		$ 158

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

[2] Represents amounts before deducting $333 million and $314 million at December 31, 2016 and 2015, 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, 2016 USD ($)	Dec. 31, 2015 USD ($)
Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value		$ 181	$ 259
Liabilities, Fair Value		$ 35	$ 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		$ 91	$ 107
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]	(11.88)	(161.36)
Minimum [Member] | Forward Prices [Member] | Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	18.07	15.08
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]	6.93	8.76
Maximum [Member] | Forward Prices [Member] | Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	38.80	37.27

[1] Represents price per megawatt-hour

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Fair Value Measurements (Level 3 Reconciliation) (Details) - Fair Value, Inputs, Level 3 [Member] - Price Risk Management Instruments [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Liability balance as of January 1		$ 89	$ 69
Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts	[1]	(34)	20
Liability balance as of December 31		$ 55	$ 89

[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.

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Fair Value Measurements (Carrying Amount And Fair Value Of Financial Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Carrying Amount [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	$ 348	$ 348
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	15,813	14,818
Fair Value Inputs Level2 [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	352	354
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	$ 17,790	$ 16,422

XML

Fair Value Measurements (Schedule Of Unrealized Gains Losses Related To Available-For-Sale Investments) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Schedule of Available-for-sale Securities [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value		$ 333	$ 314
Money Market Investments [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		9	36
Total Unrealized Gains		0	0
Total Unrealized Losses		0	0
Total Fair Value		9	36
Global equity securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		584	508
Total Unrealized Gains		1,157	1,034
Total Unrealized Losses		(3)	(9)
Total Fair Value		1,738	1,533
Fixed-Income Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		1,156	1,165
Total Unrealized Gains		48	58
Total Unrealized Losses		(12)	(8)
Total Fair Value		1,192	1,215
Securities (Assets) [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	[1],[2]	1,749
Total Unrealized Gains	[1],[2]	1,205
Total Unrealized Losses	[1],[2]	(15)
Total Fair Value	[1],[2]	$ 2,939
Nuclear Decommissioning Trusts [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	[1]		1,709
Total Unrealized Gains	[1]		1,092
Total Unrealized Losses	[1]		(17)
Total Fair Value	[1]		$ 2,784

[1] Represents amount before deducting $313 million, primarily related to deferred taxes on appreciation of investment value.

[2] Represents amounts before deducting $333 million and $314 million at December 31, 2016 and 2015, respectively, primarily related to deferred taxes on appreciation of investment value.

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Fair Value Measurements (Schedule Of Maturities On Debt Securities) (Details) $ in Millions	Dec. 31, 2016 USD ($)
Fair Value Measurements [Abstract]
Less than 1 year	$ 13
1-5 years	419
5-10 years	255
More than 10 years	505
Total maturities of debt securities	$ 1,192

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Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value Measurements [Abstract]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 1,295	$ 1,268	$ 1,336
Gross realized gains on sales of securities held as available-for-sale	18	55	118
Gross realized losses on sales of securities held as available-for-sale	$ (26)	$ (37)	$ (12)

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Employee Benefit Plans (Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Noncurrent liability		$ (2,641)		$ (2,622)
Decrease in other comprehensive income		2		1	$ 14
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1		2,035		2,092
Actual return on plan assets		167		(26)
Company contributions		52		61
Plan participant contribution		85		68
Benefits and expenses paid		(166)		(160)
Fair value of plan assets at December 31		2,173		2,035	2,092
Projected benefit obligation at January 1		1,766		1,811
Service cost for benefits earned		52		55
Interest cost		76		71	76
Actuarial (gain) loss		11		(98)
Plan amendments		37		0
Benefits and expenses paid		(153)		(146)
Federal subsidy on benefits paid		3		4
Projected benefit obligation at December 31		1,877		1,766	1,811
Current liability	[1]	(72)		(75)
Net assets (liabilities) at end of year		296		269
Noncurrent asset	[1]	368		344
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1		13,745		14,216
Actual return on plan assets		1,358		(176)
Company contributions		334		334
Benefits and expenses paid		(708)		(629)
Fair value of plan assets at December 31		14,729		13,745	14,216
Projected benefit obligation at January 1		16,299		16,696
Service cost for benefits earned		453		479
Interest cost		715		673	695
Actuarial (gain) loss		637		(922)
Plan amendments		(91)		1
Transitional costs		0
Benefits and expenses paid		(708)		(629)
Projected benefit obligation at December 31		17,305	[2]	16,299	$ 16,696
Current liability		(7)		(6)
Noncurrent liability		(2,569)		(2,547)
Net assets (liabilities) at end of year		$ (2,576)		$ (2,553)

[1] At December 31, 2016 and 2015, 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 $15.6 billion and $14.7 billion at December 31, 2016 and 2015, respectively.

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Employee Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		$ 52	$ 55	$ 45
Interest cost		76	71	76
Expected return on plan assets		(107)	(112)	(103)
Amortization of prior service cost		15	19	23
Amortization of net actuarial loss		4	4	2
Net periodic benefit cost		40	37	43
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		453	479	383
Interest cost		715	673	695
Expected return on plan assets		(828)	(873)	(807)
Amortization of prior service cost		8	15	20
Amortization of net actuarial loss		24	10	2
Net periodic benefit cost		372	304	293
Less: transfer to regulatory account	[1]	(34)	34	42
Total		$ 338	$ 338	$ 335

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

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Employee Benefit Plans (Estimated Amortized Net Periodic Benefit For 2016) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 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	(7)
Unrecognized net actuarial loss	22
Total	$ 15

XML

Employee Benefit Plans (Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	5.30%
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate range	4.05-4.19	4.27-4.48	3.89-4.09
Expected return on plan assets percentage range	2.80-6.00	3.20-6.60	3.30-6.70
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.11%	4.37%	4.00%
Average rate of future compensation increases	4.00%	4.00%	4.00%
Expected return on plan assets	5.30%	6.10%	6.20%

XML

Employee Benefit Plans (Schedule Of Assumed Health Care Cost Trend) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Employee Benefit Plans [Abstract]
Effect on postretirement benefit obligation, One-Percentage-Point Increase	$ 118
Effect on postretirement benefit obligation, One-Percentage-Point Decrease	(120)
Effect on service and interest cost, One-Percentage-Point Increase	9
Effect on service and interest cost, One-Percentage-Point Decrease	$ (10)
Assumed health care cost trend rate	7.20%
Ultimate trend rate	4.50%
Assumed return	5.30%
10 year actual rate of return	7.30%
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used	696

XML

Employee Benefit Plans (Target Asset Allocation Percentages) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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%	58.00%
Fixed Income Securities[Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	58.00%	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%	7.00%	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%	32.00%	31.00%
Global Equity Securities [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	27.00%	25.00%	25.00%

XML

Employee Benefit Plans (Schedule Of Fair Value Of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	$ 16,999	$ 15,793
Total Fair Value Of Trust Other Net Assets	97	13
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	2,177	2,040
Assets measured at NAV	1,153	1,065
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	14,822	13,753
Assets measured at NAV	5,950	5,308
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	368	343
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	3,724	3,572
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	656	632
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	5,143	4,870
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
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	5	3
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	33	20
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	733	622
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	33	20
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	364	247
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	375
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	70	69
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	610	581
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	70	69
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	610	581
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	0	0
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	0	0
Global Equity Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	115	104
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	996	903
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	115	104
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	996	903
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	0	0
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	0	0
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

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Employee Benefit Plans (Schedule Of Level 3 Reconciliation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	$ 15,793
Balance as of December 31	16,999	$ 15,793
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	2,040
Balance as of December 31	2,177	2,040
Other Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	343
Balance as of December 31	368	343
Other Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	632
Balance as of December 31	656	632
Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	0
Balance as of December 31	0	0
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	13,753
Balance as of December 31	14,822	13,753
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	3,572
Balance as of December 31	3,724	3,572
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	4,870
Balance as of December 31	5,143	4,870
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	3
Balance as of December 31	5	3
Corporate Fixed Income Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	782
Balance as of December 31	806	782
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	150
Balance as of December 31	150	150
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	632
Balance as of December 31	656	632
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	0
Balance as of December 31	0	0
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	6,339
Balance as of December 31	6,533	6,339
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	1,841
Balance as of December 31	1,754	1,841
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	4,495
Balance as of December 31	4,774	4,495
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	3	12
Relating to assets still held at the reporting date	3	(3)
Relating to assets sold during the period	0	1
Purchases	0	2
Settlements	(1)	(9)
Balance as of December 31	$ 5	$ 3

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Employee Benefit Plans (Schedule Of Estimated Benefits Expected To Be Paid) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
2017	$ 739
2018	781
2019	821
2020	857
2021	892
Thereafter in the succeeding five years	4,879
Employer contribution	334	$ 334
Expected employer contribution next year	327
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2017	87
2018	93
2019	97
2020	103
2021	108
Thereafter in the succeeding five years	592
Employer contribution	52	$ 61
Expected employer contribution next year	61
Federal Subsidy [Member]
Defined Benefit Plan Disclosure [Line Items]
2017	(8)
2018	(9)
2019	(10)
2020	(10)
2021	(11)
Thereafter in the succeeding five years	$ (15)

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Employee Benefit Plans (Schedule Of Employer Contribution Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Employee Benefit Plans [Abstract]
Retirement Savings Plan expense	$ 97	$ 89	$ 80

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Resolution Of Remaining Chapter 11 Disputed Claims (Changes In The Remaining Net Disputed Claims Liability) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Apr. 12, 2004
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Escrow for payment of remaining net disputed claims	$ 0	$ 228	$ 1,700
Net disputed claims and customer refunds	236	$ 454
Increase Decrease To Disputed Claims Liability Balance	231
Increase Decrease To Escrow For Payment Of Remaining Net Disputed Claims	161
CAISO And PX [Member]
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Increase Decrease To Disputed Claims Liability Balance	165
Increase Decrease To Escrow For Payment Of Remaining Net Disputed Claims	$ 66

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Related Party Agreements And Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Current receivables	$ 18	$ 22
Current payables	22	21
Administrative Services Provided To PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility revenues from	7	6	$ 5
Administrative Services Received From PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility expenses from	74	53	54
Utility Employee Benefit Due To PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility expenses from	$ 91	$ 82	$ 70

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Commitments And Contingencies (Legal And Regulatory Contingencies) (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Loss Contingencies [Line Items]
PSEP disallowed capital expenditures		$ 507,000	$ 407,000	$ 116,000
Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
PSEP disallowed capital expenditures		507,000	407,000	$ 116,000
Utility [Member]
Loss Contingencies [Line Items]
Accrued legal liabilities		45,000	63,000
Butte Fire [Member]
Loss Contingencies [Line Items]
Cumulative Legal Expenses Related to Butte Fire		$ 27,000
Number Of Structures Burned By Fire		44
Vegetation Management Contractors		2
Total Insurance Coverage		$ 900,000
Number Of Homes Burned By Fire		549
Number Of Households Represented In Court		950
Number of Master Complaints		2
Number Of Outbuildings Burned By Fire		368
Number of plaintiffs		1,950
Number Of Fatalities Caused By Fire		2
Number Of Commerical Properties Burned By Fire		4
Fire Fighting Costs Recovery Requested		$ 90,000
Number Of Acres Burned		70,868
Gas Distribution OII [Member]
Loss Contingencies [Line Items]
New Penalty Assessed By CPUC In Modified Presiding Officer Decision		$ 25,600
Fine Paid For Carmel Incident		10,850
SED proposed an additional fine to the Utility		7,000
Criminal Investigation [Member]
Loss Contingencies [Line Items]
Total maximum penalties		$ 3,000
Number of Alleged Felony Counts		1
Number Of Counts The Jury Acquitted Utility		6
Guilty Felony Count Of Obstructing Federal Agency Proceeding		1
Number Of Counts Of Violations Of Integrity Management Regulations		5
Dismissed Alleged Count Of Violation		1
Number Of Years For Coporate Probation Period		5 years
Number Of Years With Oversight By Third Party Monitor		5 years
Number Of Years With Oversight By Third Party Monitor With Early Termination		3 years
Maximum [Member]
Loss Contingencies [Line Items]
S E D fines for self reported violations		$ 16,800
Safety And Enforcement Division Maximum Statutory Penalty Per Violation		50
Minimum [Member]
Loss Contingencies [Line Items]
S E D fines for self reported violations		$ 50
Ex Parte Communications [Member]
Loss Contingencies [Line Items]
Total Ex Parte Communications		164
CPUC Imposed Penalty Per Day Per Violation		$ 50
Penalty Decision Future Charges and Costs [Member]
Loss Contingencies [Line Items]
Disallowed Revenue For Pipeline Safety Expenses	[1]	32,000
Total Penalty Decision Fines And Remedies		32,000
Shareholder Funded Pipeline Safety Enhancement Plan Work		850,000
Penalty Decision Cumulative Charges [Member]
Loss Contingencies [Line Items]
Customer bill credit paid		400,000
Disallowed Revenue For Pipeline Safety Expenses	[1]	129,000
Payment To State General Fund		300,000
Total Penalty Decision Fines And Remedies		1,518,000
PSEP disallowed capital expenditures	[2]	689,000
Total Penalty Decision [Member]
Loss Contingencies [Line Items]
Customer bill credit paid		400,000
C P U C Remedial Measures	[3]	50,000
Disallowed Revenue For Pipeline Safety Expenses	[1]	161,000
Payment To State General Fund		300,000
Total Penalty Decision Fines And Remedies		1,600,000
PSEP disallowed capital expenditures	[2]	689,000
Insurance Receivable [Member] | Butte Fire [Member]
Loss Contingencies [Line Items]
Balance at December 31, 2015		0
Accrued Insurance Recoveries		625,000
Reimbursements		(50,000)
Balance at December 31, 2016		575,000	$ 0
Potential Safety Citation [Member]
Loss Contingencies [Line Items]
Fines Related to Non-Operator Inspectors		$ 5,050
Amount of Time Required by the SED between Inspections		39 months
Fine For Not Completing Inspection Within Scheduled Time Frame		$ 350
Number Of Noncompliant Atmospheric Corrosion Inspections		550,000
Percent Of Noncompliant Atmospheric Corrosion Inspections		35.00%
Fine For Not Reporting Self Identified Violations Within Ten Days Of Discovery		$ 50
SED Administrative Limit per Safety Citation		8,000
Pipeline Safety Enhancement Plan [Member]
Loss Contingencies [Line Items]
CPUC authorized recovery		766,000
Capitalized PSEP costs		1,350,000
Pipeline Safety Enhancement Plan Charges		665,000
2015-2018 [Member]
Loss Contingencies [Line Items]
GT&S Capital Dissallowance		85,000
2011-2014 [Member]
Loss Contingencies [Line Items]
GT&S Capital Dissallowance		$ 134,000
Alleged Obstruction of NTSB Investigation [Member]
Loss Contingencies [Line Items]
Number of Alleged Felony Counts		12

[1] GT&S revenues have been reduced for these unrecovered expenses. The remaining charges will be recognized in the first quarter of 2017.

[2] The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs. On December 1, 2016, the CPUC issued a final phase two decision in the Utility’s 2015 GT&S rate case which allocates $689 million of the $850 million penalty to capital expenditures.

[3] In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision. This table does not reflect the Utility’s remedy-related costs already incurred or the Utility’s estimated future remedy-related costs.

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Commitments And Contingencies (Loss Accrual) (Details) - Butte Fire [Member] - Loss Accrual [Member] $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Loss Contingencies [Line Items]
Balance at December 31, 2015	$ 0
Accrued losses	750
Payments	(60)
Balance at December 31, 2016	$ 690

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Commitments And Contingencies (Impact Of Penalty Decision) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Impact Of Penalty Decision [Line Items]
Charge for disallowed capital		$ 507	$ 407	$ 116
Penalty Decision [Member]
Impact Of Penalty Decision [Line Items]
Charge for disallowed capital	[1]	283
Total Penalty Decision Fines And Remedies		412
Disallowed Revenue For Pipeline Safety Expenses	[2]	129
Total Penalty Decision [Member]
Impact Of Penalty Decision [Line Items]
Fine paid to the state		300
Customer bill credit paid		400
Charge for disallowed capital	[1]	689
Total Penalty Decision Fines And Remedies		1,600
CPUC estimated cost of other remedies	[3]	50
Disallowed Revenue For Pipeline Safety Expenses	[2]	161
Penalty Decision Cumulative Charges [Member]
Impact Of Penalty Decision [Line Items]
Fine paid to the state		300
Customer bill credit paid		400
Charge for disallowed capital	[1]	689
Total Penalty Decision Fines And Remedies		1,518
Disallowed Revenue For Pipeline Safety Expenses	[2]	129
Penalty Decision Future Charges and Costs [Member]
Impact Of Penalty Decision [Line Items]
Total Penalty Decision Fines And Remedies		32
Disallowed Revenue For Pipeline Safety Expenses	[2]	32
Pacific Gas And Electric Company [Member]
Impact Of Penalty Decision [Line Items]
Charge for disallowed capital		$ 507	$ 407	$ 116

[1] The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs. On December 1, 2016, the CPUC issued a final phase two decision in the Utility’s 2015 GT&S rate case which allocates $689 million of the $850 million penalty to capital expenditures.

[2] GT&S revenues have been reduced for these unrecovered expenses. The remaining charges will be recognized in the first quarter of 2017.

[3] In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision. This table does not reflect the Utility’s remedy-related costs already incurred or the Utility’s estimated future remedy-related costs.

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Commitments And Contingencies (Environmental Remediation Liability Composed) (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Topock natural gas compressor station	$ 299	$ 300
Hinkley natural gas compressor station	135	140
Former manufactured gas plant sites owned by the Utility or third parties	285	271
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites	131	164
Fossil fuel-fired generation facilities and sites	108	94
Total environmental remediation liability	$ 958	$ 969

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Commitments And Contingencies (Environmental Remediation Contingencies) (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$ 671,000
Utility Undiscounted Future Costs	$ 1,900
Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Remediation cost recovery	90.00%

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Commitments And Contingencies (Nuclear Insurance) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Long-term Purchase Commitment [Line Items]
Maximum total payment incurred per event under the loss sharing program	$ 375
Nuclear Incident [Member]
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	3,200
Non Nuclear Incident [Member]
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	2,600
EMANI [Member]
Long-term Purchase Commitment [Line Items]
Full insurance policy limit	200
Potential premium obligation	2
NEIL [Member]
Long-term Purchase Commitment [Line Items]
Potential premium obligation	60
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 annual payment incurred per event under the loss sharing program	255
Coverage for purchased public liability insurance, per incident	38
Humboldt Bay Unit [Member]
Long-term Purchase Commitment [Line Items]
Amount of property damage coverage provided by NEIL	131
Amount of liability insurance for Humboldt bay Unit 3	53
Humboldt Bay Unit [Member] | Nuclear Incident [Member]
Long-term Purchase Commitment [Line Items]
Amount of indemnification from the NRC for public liability arising from nuclear incidents	$ 500

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Commitments And Contingencies (Third-Party Power Purchases) (Details) $ in Millions	Dec. 31, 2016 USD ($)
Long-term Purchase Commitment [Line Items]
2017	$ 4,050
2018	3,370
2019	3,322
2020	3,273
2021	2,991
Thereafter	30,097
Total	47,103
Renewable Energy Power Purchase Agreements [Member]
Long-term Purchase Commitment [Line Items]
2017	2,233
2018	2,108
2019	2,144
2020	2,139
2021	2,117
Thereafter	27,685
Total	38,426
Other Power Purchase Agreements [Member]
Long-term Purchase Commitment [Line Items]
2017	369
2018	284
2019	225
2020	179
2021	147
Thereafter	653
Total	1,857
Nuclear Fuel Purchase Commitments [Member]
Long-term Purchase Commitment [Line Items]
2017	97
2018	93
2019	95
2020	130
2021	49
Thereafter	136
Total	600
Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
2017	536
2018	169
2019	160
2020	148
2021	93
Thereafter	455
Total	1,561
Conventional Energy [Member]
Long-term Purchase Commitment [Line Items]
2017	815
2018	716
2019	698
2020	677
2021	585
Thereafter	1,168
Total	$ 4,659

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Commitments And Contingencies (Third-Party Power Purchase Agreements) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Qualifying Facilities [Member]
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase commitments, date of contract expiration, beginning date	2017
Long term contract for purchase commitments, date of contract expiration, ending date	2028
Present value of fixed capacity payments, portion classified as current liabilities	$ 17	$ 19
Present value of fixed capacity payments, portion classified as noncurrent liabilities	18	35
Capitalized asset for fixed capacity payments for corresponding assets	35	54
Capitalized asset for fixed capacity payments, accumulated amortization	$ 148	147
Renewable Energy [Member]
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase commitments, date of contract expiration, beginning date	2017
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]
Costs Of Power Purchase	$ 3,500	$ 3,500	$ 3,600
Conventional Energy [Member]
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase commitments, date of contract expiration, beginning date	2017
Long term contract for purchase commitments, date of contract expiration, ending date	2033

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Commitments And Contingencies (Gas Supply, Transportation And Storage) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Cost of natural gas purchases	$ 700	$ 900	$ 1,400
Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase Commitments Expiration Beginning Date	2017
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase Commitments Expiration Beginning Date	2017
Long Term Contract For Purchase Commitments Expiration Ending Date	2025
Payments for Nuclear Fuel	$ 100	$ 128	$ 105

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Other Commitments And Other Operating Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments And Contingencies [Abstract]
2017	$ 44
2018	41
2019	39
2020	39
2021	36
Thereafter	168
Total	367
Payments for other commitments and operating leases	$ 43	$ 41	$ 42
Property Subject To Or Available For Operating Lease Expiration Beginning Date	2017
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating expenses	$ (15,489)	$ (15,325)	$ (14,640)
Interest income	23	9	9
Interest expense	(829)	(773)	(734)
Other income (expense)	91	117	70
Income Before Income Taxes	1,462	861	1,795
Income tax provision (benefit)	55	(27)	345
Income Available for Common Shareholders	1,393	874	1,436
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
Net change in investments (net of taxes $0, $12, and $17, at respective dates)	0	(17)	(25)
Total other comprehensive income (loss)	(2)	(18)	(39)
Comprehensive Income	$ 1,405	$ 870	$ 1,411
Weighted average common shares outstanding, basic	499	484	468
Weighted average common shares outstanding, diluted	501	487	470
Net earnings per common share, basic	$ 2.79	$ 1.81	$ 3.07
Net earnings per common share, diluted	$ 2.78	$ 1.79	$ 3.06
PG&E Corporation [Member]
Administrative service revenue	$ 70	$ 51	$ 51
Operating expenses	(73)	(53)	(53)
Interest income	1	1	1
Interest expense	(10)	(10)	(14)
Other income (expense)	2	30	(1)
Equity in earnings of subsidiaries	1,388	852	1,413
Income Before Income Taxes	1,378	871	1,397
Income tax provision (benefit)	15	3	39
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
Pension and other postretirement benefit plans (net of taxes of $1, $0, $10, at respective dates)	(2)	(1)	(14)
Net change in investments (net of taxes $0, $12, and $17, at respective dates)	0	(17)	(25)
Total other comprehensive income (loss)	(2)	(18)	(39)
Comprehensive Income	$ 1,391	$ 856	$ 1,397
Weighted average common shares outstanding, basic	499	484	468
Weighted average common shares outstanding, diluted	501	487	470
Net earnings per common share, basic	$ 2.79	$ 1.81	$ 3.07
Net earnings per common share, diluted	$ 2.78	$ 1.79	$ 3.06

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Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Balance Sheet) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash and cash equivalents	$ 177	$ 123	$ 151	$ 296
Advances to affiliates	22	21
Income taxes receivable	160	155
Other Assets, Current	283	338
Total current assets	6,164	5,813
Equipment	72,595	67,342
Accumulated depreciation	(22,014)	(20,619)
Net property, plant, and equipment	50,581	46,723
Income taxes receivable	70	135
Other	1,226	1,064
TOTAL ASSETS	68,598	63,234
Short-term borrowings	1,516	1,019
Long-term debt, classified as current	700	160
Other	2,323	1,997
Total current liabilities	7,564	6,363
Long-term debt	16,220	15,925
Other	2,279	2,326
Total noncurrent liabilities	42,842	40,043
Common stock	12,198	11,282
Reinvested earnings	5,751	5,301
Accumulated other comprehensive income (loss)	(9)	(7)
Total shareholders' equity	17,940	16,576
TOTAL LIABILITIES AND EQUITY	68,598	63,234
PG&E Corporation [Member]
Cash and cash equivalents	106	64	$ 96	$ 231
Advances to affiliates	24	22
Income taxes receivable	25	24
Other Assets, Current	0	1
Total current assets	155	111
Equipment	2	2
Accumulated depreciation	(2)	(2)
Net property, plant, and equipment	0	0
Investments in subsidiaries	18,172	16,837
Other investments	133	130
Deferred income taxes	267	250
Total noncurrent assets	18,572	17,217
TOTAL ASSETS	18,727	17,328
Accounts payable - other	7	3
Other	274	246
Total current liabilities	281	249
Long-term debt	348	348
Other	158	155
Total noncurrent liabilities	506	503
Common stock	12,198	11,282
Reinvested earnings	5,751	5,301
Accumulated other comprehensive income (loss)	(9)	(7)
Total shareholders' equity	17,940	16,576
TOTAL LIABILITIES AND EQUITY	$ 18,727	$ 17,328

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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, 2016	Dec. 31, 2015	Dec. 31, 2014
Net income		$ 1,407	$ 888	$ 1,450
Deferred income taxes and tax credits, net		1,030	693	690
Net cash provided by operating activities		4,409	3,780	3,690
Other		13	22	114
Net cash used in investing activities		(5,526)	(5,211)	(4,714)
Borrowings under revolving credit facilities		0	0	(260)
Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014		983	1,123	2,308
Repayments of long-term debt		160	0	889
Common stock issued		822	780	802
Common stock dividends paid		(921)	(856)	(828)
Other		(44)	(27)	29
Net cash (used) in financing activities		1,171	1,403	879
Net change in cash and cash equivalents		54	(28)	(145)
Cash and cash equivalents at January 1		123	151	296
Cash and cash equivalents at December 31		177	123	151
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs		17	27	17
Cash received (paid) for:
Interest, net of amounts capitalized		(726)	(684)	(633)
Income taxes, net		231	77	501
Noncash common stock issuances		(20)	(21)	(21)
Common stock dividends declared but not yet paid		(248)	(224)	(217)
PG&E Corporation [Member]
Net income		1,393	874	1,436
Stock-based compensation amortization		74	66	65
Equity in earnings of subsidiaries		(1,388)	(852)	(1,413)
Deferred income taxes and tax credits, net		11	10	(72)
Noncurrent income taxes receivable/payable		0	0	5
Current income taxes receivable/payable		(1)	5	(16)
Other		(24)	(70)	43
Net cash provided by operating activities		65	33	48
Investment in subsidiaries		(835)	(705)	(978)
Dividends received from subsidiaries	[1]	911	716	716
Proceeds from tax equity investments		0	0	368
Other		0	0	0
Net cash used in investing activities		76	11	106
Borrowings under revolving credit facilities		0	0	(260)
Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014		0	0	347
Repayments of long-term debt		0	0	(350)
Common stock issued		822	780	802
Common stock dividends paid	[2]	(921)	(856)	(828)
Net cash (used) in financing activities		(99)	(76)	(289)
Net change in cash and cash equivalents		42	(32)	(135)
Cash and cash equivalents at January 1		64	96	231
Cash and cash equivalents at December 31		106	64	96
Cash received (paid) for:
Interest, net of amounts capitalized		(9)	(9)	(15)
Income taxes, net		(13)	0	1
Noncash common stock issuances		20	21	21
Common stock dividends declared but not yet paid		$ 248	$ 224	$ 217

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

[2] In January of 2016, PG&E Corporation paid a quarterly common stock dividend of $0.455 per share. In April, July and October of 2016, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share. In January, April, July, and October of 2015 and 2014, 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule II - Consolidated Valuation And Qualifying Accounts [Abstract]
Allowance for uncollectible accounts, Balance at Beginning of Period	[1]	$ 54	$ 66	$ 80
Allowance for uncollectible accounts, Charged to Costs and Expenses	[1]	50	43	41
Allowance for uncollectible accounts, Deductions	[1],[2]	46	55	55
Allowance for uncollectible accounts, Balance at End of Period	[1]	$ 58	$ 54	$ 66

[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.